WO2022149052A1

WO2022149052A1 - Regenerative reheating geothermal power plant and method

Info

Publication number: WO2022149052A1
Application number: PCT/IB2022/050015
Authority: WO
Inventors: Alessio BARDI; Andrea Lazzaretto; Giovanni MANENTE; Marco PACI
Original assignee: Enel Green Power S.P.A.; Università Degli Studi Di Padova
Priority date: 2021-01-05
Filing date: 2022-01-03
Publication date: 2022-07-14

Abstract

The present invention refers to the field of geothermal plants, and in particular it relates to a configuration of a regenerative reheating geothermal plant, whereby steam is separated from the wellhead liquid in a backpressure turbine unit and expanded therein; the wet steam at the exhaust of the backpressure turbine group is then superheated using the heat of the separated wellhead liquid, to be finally sent to a condensing steam turbine unit for expansion up to condensing pressure. Thanks to this configuration, both the enthalpy jump and the isoenthropic efficiency of the expansion process are increased.

Description

REGENERATIVE REHEATING GEOTHERMAL POWER PLANT AND

METHOD

DESCRIPTION

Technical field of the invention The present invention refers to the field of geothermal plants, and in particular it relates to a configuration of a regenerative reheating geothermal plant, as well as to a method according to which the plant is operating.

Background of the invention

In the field of geothermal plants, solutions have recently been proposed which relate to the hypothesis of improving the performances of the so-called single-Flash and double-Flash steam plants, the basic configurations of which are well known to those skilled in the art. Suffice it to recall here that, upstream of the steam expansion stage and relative power generation, a Flashing process of the geothermal fluid is provided (i.e. a controlled pressure drop, by means of a lamination valve, which generates steam) with separation of the steam from the liquid component and expansion of this steam in the turbine (single Flash). In the case of double Flash, the liquid state leaving the first separator undergoes a second isoenthalpic pressure drop and the resulting saturated mixture enters a second separator where the saturated steam is transferred to a second (low-pressure) turbine stage. The aforementioned improvements are attributable to the following two types of plant modification:

- "Self-Superheating" (SSFI), proposed by Mathieu-Potvin (in: Mathieu-Potvin F., Self-Superheating: A new paradigm for geothermal power plant design, Geothermics 48 (2013) 16-30). This configuration, which can be applied to both single-Flash and double- Flash geothermal steam power plants, is based on a regenerative process that essentially consists of using the geothermal fluid entering each separator to superheat the steam leaving the separator. In the study, a state of saturated (or subcooled) liquid at the wellhead is assumed before lamination, although in most geothermal systems the wellhead fluid is two-phase. The theoretical efficiency advantages of this configuration, for which reference should be made to the content of the aforementioned publication, therefore derive from the assumption, which is precisely theoretical by nature, on a geothermal fluid condition that is distant from the real condition (two-phase geothermal fluid composed of one third steam and two thirds liquid). This real condition greatly downsizes the anticipated advantages of the SSH configuration.

- Interstage reheating (Double Flash ReHeating - 2FRH) proposed by Ronald DiPippo (DiPippo R., Geothermal double-Flash plant with interstage reheating: An updated and expanded thermal and exergetic analysis and optimization, Geothermics 48 (2013) 121-131 , a publication updating an earlier 1991 publication by the same author). This plant diagram is only applied to double-Flash steam power plants. Interstage reheating is a regenerative process which consists in superheating the wet steam exiting the turbine at high pressure using the hot geothermal liquid separated by a wellhead. The cooled liquid is then laminated to generate saturated steam and mixed with the superheated steam before admission to the low-pressure turbine. In this case, several aspects relating to the addition of the second Flashing process are open to comments. For example, and in particular, the Flashing process causes an increase in the concentration of silica in the liquid together with a decrease in the temperature at which the geothermal liquid is re-injected, a temperature which could be lower than the silica precipitation point. Mixing with saturated steam at the turbine inlet causes a reduction in the steam title at the outlet and consequently a reduction in turbine efficiency. Moreover, the mixing process is itself a source of irreversibility. To summarise, the second Flashing process, assuming it does not cause problems with silica precipitation, not only makes the configuration more complex but also reduces the advantages that could be obtained from reheating.

Summary of the invention

Starting from the critical observation of the above-mentioned configurations, the present Applicants have identified, according to the present invention, a different configuration, capable of achieving, with respect to the known plant diagrams, a significant increase in the power output under the same other conditions, while at the same time overcoming some important drawbacks of the above-mentioned diagrams, such as in particular the plant complication and the precipitation of silica in the geothermal fluid. The geothermal plant configuration according to the invention, and the relative method based on a regenerative superheating process (SelfReheating - SRFI) have the essential features as set out in the appended independent claims. Further advantageous features are the subject-matter of dependent claims.

Short description of the drawings

The characteristics and advantages of the regenerative reheating geothermal plant and method according to the present invention will appear more clearly from the following description of an embodiment thereof, provided by way of non-limiting example with reference to the appended drawings wherein:

- Figure 1 is a schematic process diagram of a geothermal plant including the configuration according to the present invention; - Figure 2 is a process diagram according to a modelling of a plant according to the present invention;

- Figures 3a and 3b are diagrams of the power output by the plant according to the invention as a function of the backpressure at the exhaust of a first turbine of the system: the diagram in Figure 3a shows in particular the total power output by the two turbines of the plant (continuous curve) and temperature of the re-injected geothermal liquid (dashed curve), while the diagram in Figure 3b shows the power output by a first turbine (dashed curve) by the second turbine (section-point curve) and total power output (continuous curve);

- Figures 4a and 4b are diagrams of the isoenthropic efficiency and of the steam fraction at the turbine outlet as a function of the backpressure at the exhaust of the first turbine: the diagram in Figure 4a illustrates in particular the isoenthropic efficiency of the (first) backpressure steam turbine (dashed curve) and of the expansion process of the (second) condensing turbine in the wet steam zone (line-point point), while Figure 4b represents a diagram of the steam fraction at the outlet of the first turbine (dashed curve) and of the second turbine (line-point curve) respectively;

- Figure 5 is a diagram of the variation of the superheating of the steam at the inlet of the second turbine (continuous curve) and cooling of the geothermal liquid (dashed curve) as the backpressure at the exhaust of the first turbine varies;

- Figures 6a and 6b are T-q diagrams of a regenerative heat exchanger of the plant according to the invention, respectively (Figure 6a) with pressure at the exhaust of the first turbine at 1.4 bar and TTD=10°C, and (Figure 6b) with pressure at the exhaust of the first turbine at 2.1 bar and TTD=10°C; and

- Figures 7a and 7b are T-s diagrams of the configuration of the present plant corresponding respectively to the conditions of Figures 6a and 6b above. Detailed description of the invention

A first aspect of the plant and process according to the invention is the superheating of steam obtained by a regenerative process, namely by directly using the steam separated in a wellhead in a backpressure turbine where it is expanded at a pressure generally higher than the atmospheric pressure. The wet steam at the exhaust of the backpressure turbine is heated using the heat of the separated liquid in the wellhead and sent to a second steam turbine for expansion up to the pressure of the condenser. Reheating increases both the enthalpy jump and the isoenthropic efficiency of the expansion process. The increase in the latter is due to the steam title at the exit of the second (condensing) turbine in which the steam title is much higher than that obtained in the expansion in a single-stage condensing steam turbine.

According to one embodiment, the geothermal plant comprises separator means 2 of a liquid component from a steam component of a geothermal fluid exiting a wellhead 1 ; turbine means 4, 5 in which the steam component is expanded resulting in the collection of mechanical power, comprising a first turbine body 4 and a second turbine body 5 for expanding the steam component at higher and lower pressures, respectively; heat exchanger means 3 interposed in fluid communication between the first and second turbine bodies 4, 5 and hydraulically communicating with the separator means 2, the heat exchanger means 3 being adapted to superheat the steam component exiting the first turbine body 4 by using the enthalpy of the liquid component exiting the separator 2, thereby producing a superheated steam component, the geothermal fluid exiting the wellhead 1 being directly fed into the separator means 2 without undergoing heat exchange processes and/or lamination processes upstream of the separator means, and the superheated steam component downstream of the heat exchanger means 3 being directly fed into the second turbine body 5. Preferably, the geothermal fluid is at medium pressure in two-phase conditions with variable liquid-steam percentages, and preferably, the geothermal plant is configured to superheat the steam up to the maximum allowed temperature, i.e. to the temperature of the separated liquid less the terminal temperature difference of the self reheater heat exchanger.

According to one embodiment, condensing pressure is reduced at the same time in order to maximise the power by allowing the enthalpy jump and the expansion efficiency to be maximised.

It should be noted that the overall enthalpy jump of the steam in the expansion, the sum of the enthalpy jumps in the first and second turbine body, is much greater than the enthalpy jump obtainable in a single body expanding the saturated steam at medium pressure up to the above-mentioned sub-atmospheric condensing pressure.

Furthermore, the isoenthropic efficiencies of the first turbine body 4 and second turbine body 5 are configured to be both greater than the isoenthropic efficiency of a single turbine body expanding steam at medium pressure up to sub-atmospheric condensing pressure, due to the lower liquid fraction in the expansion processes in the first and second turbine body.

In more detail, and with reference to Figures 1 and 2, the plant diagram in Figure 1 shows: the geothermal fluid line is marked with a regular cross-hatch; the liquid circuit lines are marked with a thin continuous line; the steam circuit lines are marked with a thin irregular cross-hatch; the gas circuit lines are marked with a thin regular line; and the mechanical energy collection axis is marked with a continuous line.

The following components can also be identified:

1 - Wellhead

2 - Steam phase-liquid phase separator, e.g. cyclone separator

3 - Regenerative heat exchanger (SRFI, Self ReFleater) 4 - First high-pressure (backpressure) steam turbine body, formed by a group of turbine stages

5 - Second low-pressure (condensing) steam turbine body, formed by a group of turbine stages

6, 11 - Re-injection points 7 - Condenser (direct contact) or condenser means

8 - Gas cooler 9 - Cooling towers

10 - Cooling water pump

12, 13 - means for extracting non-condensable gases, such as centrifugal compression stages 14 - Generator

15 - Gas treatment units (such as an abatement system or absorption column)

A part of the above elements is also highlighted in the partial diagram of Figure 2, in which the components are set in a circuit symbology of clear interpretation for a person skilled in the art, and in which the second turbine body 5 is in this case, by way of not- limiting example, modelled with two blocks 51 and 52 with different isoenthropic efficiencies.

The design is based on a possible condition of the geothermal fluid extracted from the wells, which can be preferably represented as a mixture of steam (43%) and liquid (57%). At the wellhead 1 the steam phase is separated from the liquid phase in the separator 2. The steam phase, which consists of saturated steam with non-condensable gases (NCG), is expanded in the first (backpressure) steam turbine 4 up to an intermediate pressure, which is higher than the atmospheric pressure, and then sent to the regenerative heat exchanger 3. On the contrary, the separated hot liquid is sent directly to the heat exchanger 3 where it is used to complete the evaporation and superheat the wet steam leaving the first turbine 4. The steam superheated to the intermediate pressure is expanded in the second (condensing) steam turbine body 5 up to the low pressure (approx. 0.085 bar, depending on ambient conditions) of the condenser or of the condenser means 7.

In other words, the superheated steam component is fed into the second turbine body 5, the condenser means 7 in which the steam exiting the second turbine body 5 is condensed at a pressure lower than atmospheric pressure and, preferably, non condensable gas extractor means 12, 13 extract the non-condensable gases from the condenser means and send them to gas treatment units 15.

According to one embodiment, the condenser 7 is of the mixture type. Preferably, the plant comprises a mixing condenser 7, fluid-dynamically placed downstream of the second turbine body 5, said mixing condenser 7 being fluid- dynamically connected with cooling towers 9 and treatment units 15 consisting of a primary emission abatement system.

Preferably, the cooling water pump 10 is fluid-dynamically interposed between the mixing condenser 7 and the cooling towers 9. According to one embodiment, the non-condensable gases (NCG) are extracted from the condenser 7 and sent to an emission abatement system 15 (an AMIS® unit or one based on absorption and re-injection of NCG). According to one embodiment, the non-condensable gases (NCG) are sent to respective centrifugal compression stages 12, 13, which materialize the non-condensable gas extractor means, interposed between the mixing condenser 7 and the emission abatement system 15.

Preferably, a gas cooler 8 is fluid-dynamically interposed between the two centrifugal compression stages 12, 13. This gas cooler 8 is also fluid-dynamically interposed between the cooling towers 9 and the mixing condenser 7. This makes it possible to cool the non-condensable gases at the inlet of the second compression stage and thus reduce the compression work.

Compared to an SSH plant, the present plant comprises two separate steam turbines (or rather two distinct turbine bodies), and does not include any lamination valves. The saturated steam available at the outlet of the separator is expanded directly in the (first) steam turbine without any upstream process, which would cause additional irreversibility. Superheating the steam at intermediate pressure allows an increase in the steam fraction at the steam turbine outlet, which significantly improves the efficiency and the power of the turbine.

It is interesting to note that the use of the specific condensing system with mixing condenser 7 and cooling tower 9 allows the advantages of the present invention to be enhanced, as it allows lower condensing pressures to be achieved compared to a system with a surface condenser and air cooling, and consequently to further increase the enthalpy jump in the expansion process. Thanks to the high superheating, it is possible to obtain high steam titles at the condensing turbine exhaust can be achieved even at low condensing pressures in the range of 0.07-0.08 bar. The system for extracting the non-condensable gases from the mixed condenser makes it possible to keep the condensing pressures levels low, thus enhancing the advantages of the invention. In the presence of a high content of non-condensable gases in the geothermal steam (e.g. greater than 4-5%) such an extraction system can be based on multi-stage compressors with intermediate cooling (like the one shown in the figure). The invention is also applicable to geothermal fields containing a smaller amount of non-condensable gases in which the extraction of the non-condensable gases is carried out by means of steam ejectors.

According to one embodiment, the extracted non-condensable gases are sent to an AMIS-type primary emission abatement system 15 that allows 99% of the hydrogen sulfide to be abated. The secondary hydrogen sulfide emissions from the cooling tower 9 are kept low by acting on the liquid-steam equilibrium in the mixing condenser. The overall abatement of hydrogen sulfide is higher than 90%.

Typically, the adoption of the cooling towers is a technical solution adopted with reserve or even discouraged due to the high release of environmentally harmful secondary emissions. This specific technical configuration comprises the mixing condenser 7, fluid- dynamically connected with the cooling towers 9 and the primary emission abatement system 15 of the AMIS type allows the benefit produced by the cooling towers 9 to be obtained by lowering the operating temperatures and thus increasing the process power while keeping the secondary emissions within acceptable release levels. Therefore, compared to a closed-circuit condensation system, the above-mentioned system allows the power to be increased and the emissions to be kept low.

As an alternative to the primary emission abatement system 15 of the AMIS type, a primary emission abatement system 15 based on the absorption of the non condensable gases in water at high pressure can be used. In other words, preferably, the primary emission abatement system 15 is an AMIS or a system based on the absorption of the non-condensable gases in water at high pressure between 30-40 bar. In fact, in this case, hydrogen sulphide abatement levels of 95% can be achieved using absorption column pressures in the range of 30-40 bar and a quantity of water equal to the liquid separated in the separator. At the same time, CO2 emissions are abated by around 50%. The process and the geothermal plant configured to implement it preferably comprise the step of superheating the steam up to the maximum allowed temperature, which is the temperature of the separated liquid less the terminal temperature difference of the self-reheater heat exchanger. Maximising the superheating temperature at the same time as reducing the condensing pressure as previously described represents a key criterion of the present invention for maximising the power as it allows maximising the enthalpy jump and the expansion efficiency, and ultimately the power produced for predefined conditions of the geothermal fluid in the wellhead.

The Applicants have conducted specific studies and have been able to find that the aforementioned plant configuration according to the present invention for optimising the exploitation of a wellhead geofluid condition can result in an increase in power by 17% compared to the corresponding power obtained by expansion in a single condensing turbine (single Flash) and direct re-injection of brine into the well.

The Applicants have also found that the specific configuration envisaged for the present invention allows for its effective and versatile applicability to different conditions of the geothermal wellhead fluid, whereby the advantages in terms of power may in some cases be even greater than the above-mentioned value of 17%.

In terms of liquid-steam fraction, the above configuration applies preferably to a two-phase wellhead geothermal fluid condition in the composition range from 30% steam - 70% liquid up to 70% steam - 30% liquid.

Advantageously, the present invention provides the possibility of separating the evaporation processes of the wet steam leaving the backpressure turbine and superheating of the dry saturated steam into two separate components called evaporator and superheater, instead of into a single component, having different constructional features.

According to the modelling in Figure 2, referring to a plant with a generated power of 20 MW, in one embodiment the turbine means comprise the backpressure steam turbine 4, whose isoenthropic efficiency is calculated using Baumann's rule (well known from the literature), and two turbine blocks 51 , 52 with different isoenthropic efficiencies.

In other words, the second turbine body 5 comprises the first and second turbine block 51 , 52 with different characteristics, where the first block 51 is configured to produce an expansion which involves only the superheated steam fraction while the second block 52 is configured to produce an expansion of the wet steam fraction only.

In the first block 51 the expansion involves superheated steam states and the isoenthropic efficiency is advantageously set equal to about 85%. In the second block 52 the isoenthropic efficiency is calculated using Baumann's rule because the expansion involves the wet steam region. The mechanical efficiency of the steam turbines is set equal to about 95%.

According to one embodiment, the isentropic efficiency of the first block 51 is greater than the isentropic efficiency of the second block 52, since the first block 51 does not undergo the fluid-dynamic losses deriving from the presence of liquid drops.

In the exchanger 3, or re-heater, the wet steam at the outlet of the first turbine 4 is first heated at a constant temperature up to the dry saturated steam conditions and then superheated.

In other words, as far as a process aspect is concerned, the wet steam component exiting the first expansion stage is first heated at a constant temperature up to the dry saturated steam conditions and then superheated by a regenerative process using part of the heat of the separated liquid component, the heating and superheating being carried out in the same heat exchanger 3.

As mentioned, the enthalpy of the liquid separated at the wellhead is used to superheat the wet steam in the reheater. The terminal temperature difference (TTD) is set at equal to 10 °C. The flow rate of the liquid phase fed to the exchanger 3 is equal to 170 tonnes/hour and is lower than the one calculated from the phase balance between the geothermal reservoir and the wellhead. For this reason, a splitter 21 is included in the modelling between the actual separator 2 and the exchanger 3. The superheating section, which is in practice formed by the components shown in the modelling of Figure 2, can be applied as a retrofitting to plants independently of the non-condensate emission abatement system (AMIS® or absorption).

The diagrams shown in Figures 3a to 7b are representative of some significant structural and operational aspects of the plant. According to one embodiment, the geothermal plant comprises means for regulating backpressure (similar to those used in cogeneration plants with a backpressure turbine such as, for example, acting on the constructional characteristics of the turbine itself (e.g. number of stages, etc.) and on regulation systems typically used in cogeneration plants with a backpressure turbine) at the outlet of the first turbine body 4 configured to regulate a backpressure stage, having at the inlet dry saturated steam at medium pressure and at the outlet an exhaust pressure typically higher than the atmospheric pressure.

According to one embodiment, the intermediate pressure between the two turbine bodies is determined by the overall design of the two bodies (size and shape of each component, number of stages, rotation speed, etc.). Preferably, at the operational level, the intermediate pressure is modified

(advantageously in the sense of reducing it) by comprising elements which can introduce pressure drops (such as lamination valves or variable geometry nozzles which can be progressively closed to reduce pressure or re-opened to restore it to a higher value).

In other words, according to one embodiment, such backpressure regulating means comprise a lamination valve and/or a variable geometry nozzle fluid-dynamically which are positioned downstream of the outlet of the first turbine body 4.

Preferably, the second turbine body 5 is a condensing turbine with steam at the inlet configured to have a low pressure and a high degree of superheating and at the outlet an exhaust pressure equal to the sub-atmospheric condensing pressure. The overall power output by the system is influenced by the backpressure of the fluid at the exhaust of the first turbine. An increase in the backpressure above the atmospheric pressure value has a negative (decreasing) effect on the power output by the first turbine (Figure 3a) and a positive (increasing) effect on the power output by the condensing turbine(s) (Figure 3b). Considering the total power output by the two turbines, it was found that the maximum power output is obtained with a backpressure of approximately 1.4 bar ("full" points shown on the curves). Under these conditions, the separated geothermal fluid is cooled in the exchanger or superheater 3 to a temperature of approximately 141 °C, which is below the minimum allowed re-injection temperature (assumed to be 150 °C). To comply with this temperature constraint it is necessary to raise the backpressure to around 2.1 bar ("empty" points), a value which in any case allows for an overall power to be obtained only slightly below the maximum power (<0.5 %). In this regard, it is also worth noting that in the present configuration, in order to establish the optimum backpressure - as opposed to what happens in the aforementioned 2FRH double-Flash plant where this is affected by the need to generate steam in the second Flash - account can be taken only of the need to maximise the power produced by the steam separated at the wellhead (thanks to the increase in the average steam title in the expansion process). From the point of view of the isoenthropic efficiency of the two turbines (Figures 4a and 4b), there is an inverse correlation with respect to the backpressure at the exhaust of the first turbine with respect to that just seen for the absolute power (for the condensing turbine reference is made to the efficiency of the expansion in the wet region alone, the isoenthropic efficiency of dry expansion being 85%). Under the conditions relating to the maximum output power, the steam fraction at the outlet of the condensing turbine (95.8%) is considerably higher than that of the backpressure turbine (90.5%). The value of the backpressure of 2.1 (which respects the constraint on the minimum re-injection temperature) corresponds to values of outlet the steam fraction of the turbine and comparable efficiencies between the two turbines.

Again, the degree of superheating at the inlet of the condensing turbine (Figure 5) is modest at high backpressures, because under these conditions the wet steam temperature at the outlet of the first turbine is relatively high, so only a moderate superheating can be achieved at the inlet of the second turbine by recovering heat from the separated geothermal fluid. On the other hand, when the backpressure approaches the atmospheric pressure, steam superheating can reach values of up to 90-100 °C. At the above-mentioned "optimum" backpressure, in terms of achievable power, of 1.4 bar, the cooling of the geothermal liquid is higher than the maximum allowed to avoid silica precipitation. If the backpressure of the steam turbine is increased up to 2.1 bar, the cooling of the geothermal liquid does not exceed 55 °C, which allows the minimum re injection temperature to be met.

The Applicants have found that, for example, for a geothermal wellhead fluid with a composition equal to 43% steam and 57% liquid, a pressure of 18 bar and a temperature of 205°C, the optimum backpressure that maximises power is between 1.2- 1.6 bar. However, at these backpressures the silica re-injection temperature is below 150°C.

The Applicants have moreover found that a re-injection of silica at temperatures below 150°C leads to problems related to the possibility of silica precipitation with consequent reduction in the efficiency of the process as a whole due to maintenance steps aimed at removing deposits of silica and replacing any damaged parts by it.

The Applicants have therefore noted that by increasing the backpressure values at the outlet of the first turbine body by acting on the construction characteristics of the same turbine (e.g. number of stages, etc.) and on regulation systems that are typically used in cogeneration plants with backpressure turbine, it is possible to increase the silica re-injection temperature.

In other words, the backpressure downstream of the first turbine body 4 can be chosen in a wide range in order to maximise the total power produced by the first and second turbine body 4, 5. Again, the backpressure downstream of the first turbine body 4 can be chosen in a wide range in order to keep the re-injection temperature of the separated liquid component in the separator medium 2 at the required values to avoid silica precipitation.

In particular, according to one embodiment, in order to obtain silica re-injection temperatures above 150°C and to avoid precipitation problems, the geothermal plant comprises means for regulating (like those typically used in cogeneration plants with backpressure turbine) the backpressure at the outlet of the first turbine body which are configured to determine the backpressure in the range of backpressures between 2.1 bar and 3.2 bar, more preferably between 2.2 and 2.5 bar, even more preferably substantially around 2.3 bar. In this context, the term "substantially around 2.3 bar" means a range between ± 0.1 bar with respect to the value mentioned.

Finally, the Applicants have verified following specific and punctual analyses that an increase in the backpressure at the outlet of the first turbine stage leads to a reduction in the power of the process. This power reduction, if confined to the range between 2.1 bar and 3.2 bar, results in power losses of 1.5% lower than the maximum achievable power. Even more so, if the backpressure is between the preferred backpressure range defined between 2.2 and 2.5 bar, the power reduction is less than 0.5% (see the graph in Figure 3a).

The Applicants have therefore unexpectedly identified an ideal range that leads to a limited if not negligible reduction in power with a significantly inhibited silica precipitation, thus obtaining an important benefit in terms of the process as a whole and the efficiency and average life of the geothermal plant.

In other words, the technical solution identified as a plant or process comprises regulating the backpressure at the exhaust of the first turbine 4 in a range to maximise the mechanical/electrical power generated by the plant.

Preferably, regulating the backpressure downstream of the first turbine 4 in the aforementioned specific range makes it possible to comply with the constraint on the minimum re-injection temperature of the liquid component and at the same time limit the energy losses compared to the maximum power backpressure. Again, the Applicants have found that regulating the degree of superheating of the steam sent to the second turbine 5 is advantageously aimed at meeting the constraint on the minimum re-injection temperature of the liquid component.

Further, the Applicants have found that such a regenerative superheating process allows the expansion line to be shifted into the superheated steam zone or towards higher steam titles in the wet steam zone compared to an expansion without superheating.

For higher backpressures, the degree of superheating decreases and with it the overall enthalpy jump, the isoenthropic efficiency of the condensing turbine and the overall power produced. Advantageously, the scope of the present invention also covers different conditions of the geofluid (pressure, temperature, steam/liquid fraction, amount of dissolved silica, etc.) with respect to what has been previously indicated, which may however result in variations in the range of backpressure values which allow to obtain the maximum desired power. It is relevant to note the proposal to cool the geothermal liquid in the self-reheater exchanger up to the minimum re-injection temperature that avoids silica precipitation or, in the case of high backpressures, up to the minimum allowed temperature in the heat exchange with steam. This is in order to make full use of the enthalpy content while preventing problems arising from silica precipitation.

Advantageously, the present invention makes it possible to achieve a reduction in erosion phenomena in turbines due to the presence of liquid drops. In the new configuration subject-matter of the present invention, the liquid fraction at the expansion end is lower thanks to the higher steam title. This results in a decrease in erosion problems due to liquid droplets hitting the front edge of the blades. This makes it possible to increase the life of the turbine or use less expensive materials. Finally, Figures 6a and 6b are T-q diagrams respectively in the configuration at the optimum backpressure and at the suboptimal backpressure satisfying the constraint on the minimum re-injection temperature, while Figures 7a and 7b show the state diagram in the temperature-entropy (T-s) plane of the steam processes optimised in the configuration according to the invention, and again - respectively - in the two backpressure conditions proposed above.

For example, tests and simulations performed have demonstrated the effect on the performances of the terminal temperature difference in the reheater. It has been found that increasing the terminal temperature difference in the reheater causes a moderate decrease in the maximum output power (350-400 kW). The optimum backpressure of the steam turbine decreases slightly when TTD = 30 °C compared to TTD = 10 °C. The outlet temperature of the geothermal liquid is always above 140 °C for all scenarios considered. Ultimately, with backpressures of the first turbine in the 1.2- 1.5 bar range, full power output conditions are maintained regardless of the terminal temperature difference in the reheater. The characteristics described above as a function of embodiments of the geothermal plant in question are applied, at least in part, in a method for collecting mechanical power from a geothermal fluid exiting a wellhead, comprising: separating a liquid component from a steam component of the geothermal fluid; expanding the steam component, resulting in the collection of mechanical power, in two expansion processes at higher and lower pressures, respectively; superheating the steam component exiting the first expansion process using the enthalpy of the liquid component previously separated from the geothermal fluid, thereby producing a superheated steam component; discharging the geothermal fluid from the wellhead by separating it directly into said liquid and steam components without undergoing a lamination phase; superheating the superheated steam component up to the maximum allowed temperature, i.e. to the temperature of the separated liquid less the terminal temperature difference of the self-reheater heat exchanger, at the same time producing a reduction in the condensing pressure to maximise the power allowing to maximise the enthalpy jump and the expansion efficiency; directly feeding the superheated steam component up to the maximum allowed temperature in the second expansion process. According to one embodiment, the method comprises regulating the backpressure at the outlet of a first turbine body 4 by means of backpressure regulating means at an exhaust pressure higher than the atmospheric pressure.

Preferably, the backpressure at the outlet of the first turbine body 4 is in the range between 2.1 bar and 3.2 bar, more preferably between 2.2 and 2.5 bar, even more preferably substantially around 2.3 bar.

According to one embodiment, the second expansion process comprises two expansion blocks with different isoenthropic efficiencies.

Preferably, the method comprises arranging a mixing condenser 7, fluid- dynamically placed downstream of the second turbine body 5, the mixing condenser 7 being fluid-dynamically connected with cooling towers 9 and a primary emission abatement system 15 and an AMIS type primary emission abatement system 15 or a system based on the absorption of the non-condensable gases in water at high pressure between 30-40 bar in order to produce an increase in power while keeping secondary emissions within tolerance limits. From the foregoing, it is shown that some of the advantages of the invention over the above configurations comprise:

- significant increase in the output power: under optimum operating conditions the power generated by the configuration according to the invention reaches the value of 24.7 MW, which is 3.6 MW higher than the corresponding power obtained with the expansion in a single condensing turbine (Single Flash); - compliance with the solubility constraints of silica in the geothermal re-injection fluid: the liquid phase separated in the wellhead has a lower re-injection temperature limit (150°C) than the most efficient configurations (double Flash) for the same initial silica concentration in the geothermal fluid; - simplified plant engineering: the plant engineering modification compared to the single-Flash configuration consists of separating the expansion process into two turbine bodies and inserting the reheater (evaporator-superheater) between the two bodies. Although the most common solution for recovering energy in geothermal power plants fed by two-phase fluid is the installation of a binary plant with an organic Rankine cycle, this choice entails greater complexity in plant management. Preferably, the heat exchanger means 3 comprises a shell-and-tube heat exchanger with inlet wet steam on the shell side and liquid on the tube side, comprising an evaporative section adapted to increase the wet steam title up to that of dry saturated steam and a sensible heat exchange section adapted to superheat the dry saturated steam. Preferably, the thermal load of the overheating section of the heat exchanger medium 3 is significant and approximately comparable to the thermal load of the evaporative section. Preferably, the degree of superheating of the steam in the superheating section of the heat exchanger medium 3 can reach very high values, even in the range of 100°C, in relation to the pressure and temperature conditions of the geothermal fluid exiting the wellhead 1 . Preferably, specific types of surface heat exchangers may be adopted to perform the heat exchange process between the liquid leaving the separator 2 and the steam leaving the first turbine stage 4. An apparatus of this kind can in fact be associated to an exchanger for preheating feed water in a steam cycle with reheating, and as a person skilled in the art knows, it is divided into two sections: an evaporative section in which the wet steam increases its title until it becomes saturated dry and a sensible heat exchange section where the saturated dry steam is superheated;

- higher power increase than existing configurations: the power gain that would be achievable by an air-cooled organic fluid Rankine cycle recovering heat from the separated wellhead liquid up to the minimum temperature of 150 °C is about 1.6 MW, which is about 2.0 MW less than that achievable by the new configuration proposed herein. This demonstrates that, compared to using an organic-fluid Rankine cycle, the heat of the separated liquid is used more efficiently in the new plant configuration. Another possible comparison is with the traditional double Flash configuration with respect to which the power gain is about 1.1 MW with the same constraints on the minimum re-injection temperature; - reduction of erosion phenomena in the turbine due to the presence of liquid drops.

In the new configuration, the liquid fraction at expansion end is lower thanks to the higher steam title. This results in a decrease in erosion problems due to liquid droplets hitting the front edge of the blades. This makes it possible to increase the life of the turbine or use less expensive materials. With regards to the two turbine bodies, reference can obviously be made to both distinct turbines and a double-bodied turbine with rotation speeds suitable for maximizing efficiency. The first body is a backpressure turbine with an exhaust pressure higher than the atmospheric pressure, the second body is a condensing steam turbine with inlet steam characterised by a lower pressure and high superheating. The steam turbines currently used in the geothermal field have a universal design that can be applied to a variety of steam conditions, and therefore can be used as such, or with design adaptations, in the plant according to the invention. More generally, the components mentioned above consist of elements whose specific configuration within the geothermal plant and embodiment process represent a significant novel and inventive aspect. The present invention has been described hereto with reference to preferred embodiments thereof. It is intended that other embodiments may exist which relate to the same inventive concept, within the scope of protection of the claims indicated below.

Claims

1. Geothermal plant, comprising: separator means (2) of a liquid component from a steam component of a geothermal fluid exiting from a wellhead (1 ); turbine means (4, 5) in which said steam component is expanded resulting in the collection of mechanical power, comprising a first turbine body (4) and a second turbine body (5) for expanding said steam component at higher and lower pressures, respectively; heat exchanger means (3) interposed in fluid communication between said first and second turbine body (4, 5) and hydraulically communicating with said separator means (2), said heat exchanger means (3) being adapted to superheat the steam component exiting said first turbine body (4), using the enthalpy of said liquid component exiting said separator (2), thereby producing a superheated steam component, said geothermal fluid exiting the wellhead (1), being directly fed into said separator means (2), without undergoing heat exchange processes and/or lamination processes upstream of said separator means, said superheated steam component downstream of said heat exchanger means (3) presenting a high degree of superheating with respect to saturation conditions, being directly fed into said second turbine body (5), said geothermal plant being configured to superheat the steam up to the maximum allowed temperature, i.e. to the temperature of the separated liquid less the terminal temperature difference of the heat exchanger means (3), at the same time as reducing the condensing pressure to maximise the power, thus allowing the enthalpy jump and the expansion efficiency to be maximised.

2. The plant according to claim 1 , comprising a mixing condenser (7), fluid- dynamically placed downstream of said second turbine body (5), said mixing condenser (7) being fluid-dynamically connected with cooling towers (9) and a primary emission abatement system (15).

3. The plant according to claim 2, wherein said primary emission abatement system (15) is an AMIS or a system based on the absorption of the non-condensable gases in water at a high pressure between 30 bar and 40 bar.

4. The plant according to one of the preceding claims, wherein said first and second turbine body (4, 5) are realized in respective distinct turbines.

5. The plant according to claim 1 to 3, wherein said first and second turbine body (4, 5) are realized in a single double-body turbine with rotation speeds suitable for maximising the efficiency.

6. The plant according to any one of the preceding claims, comprising means for regulating the backpressure at the outlet of said first turbine body (4) configured to regulate a backpressure stage, having at the inlet dry saturated steam at medium pressure and at the outlet an exhaust pressure higher than the atmospheric pressure, and wherein said second turbine body (5) is condensing with inlet steam characterized by a low pressure and high degree of superheating and at the outlet an exhaust pressure equal to the sub-atmospheric condensing pressure.

7. The plant according to the preceding claim, wherein said means for regulating the backpressure at the outlet of said first turbine body (4) comprise a lamination valve and/or a variable geometry nozzle which are placed fluid-dynamically downstream of the outlet from the first body of turbine (4).

8. The plant according to the preceding claim, wherein said backpressure regulating means at the outlet of said first turbine body (4) are configured to set said backpressure in the range between 2.1 bar and 3.2 bar, more preferably between 2.2 bar and 2.5 bar, even more preferably substantially around 2.3 bar.

9. The plant according to any one of claims 6 to 8, wherein said second turbine body (5) comprises a first and a second turbine block (51 , 52) having different characteristics, wherein said first block (51) is configured to produce an expansion exclusively involving the superheated steam fraction while said second block (52) is configured to produce an expansion exclusively of the wet steam fraction.

10. The plant according to claim 9, wherein the isoenthropic efficiency of said first block (51) is greater than the isoenthropic efficiency of said second block (52), as said first block (51) does not undergo the fluid-dynamic losses deriving from the presence of liquid drops.

11. The plant according to any one of the preceding claims, wherein said heat exchanger means (3) comprise a shell-and-tube exchanger with inlet wet steam on the shell side and liquid on the tube side, comprising an evaporative section adapted to increase the wet steam title to that of dry saturated steam and a sensible heat exchange section adapted to superheat the dry saturated steam.

12. A method for collecting mechanical power from a geothermal fluid exiting a wellhead, comprising: separating a liquid component from a steam component of the geothermal fluid; expanding said steam component, resulting in the collection of mechanical power, in a first and a second distinct expansion process at higher and lower pressures, respectively; superheating the steam component exiting said first expansion process, by means of heat exchanger means, using the enthalpy of said liquid component previously separated from said geothermal fluid, producing a superheated steam component; expanding said superheated steam in said second expansion process up to a sub-atmospheric pressure, condensing the steam and extracting the non-condensable gases from the condenser; discharging said geothermal fluid from the wellhead, separating it directly into said liquid and steam components without previously undergoing a cooling process and/or a lamination step; superheating said superheated steam component up to the maximum allowed temperature, i.e. up to the temperature of the separated liquid less the terminal temperature difference of the heat exchanger means, while simultaneously producing a reduction in the condensing pressure in order to maximise the power allowing the enthalpy jump and the expansion efficiency to be maximised; directly feeding said superheated steam component up to the maximum allowed temperature into said second expansion stage.

13. The method according to claim 12, wherein said steam component exiting the separator is expanded in a first turbine body up to an intermediate exhaust pressure, typically higher than the atmospheric pressure, and is subsequently superheated and then expanded in a second turbine body up to the sub-atmospheric condensing pressure.

14. The method according to claim 13, comprising regulating the pressure at the outlet of the first backpressure turbine body (4) by means of backpressure regulating means at an exhaust pressure above the atmospheric pressure and optimum for maximising the power.

15. The method according to claim 14, wherein said optimum backpressure at the outlet of said first turbine body (4) is in the range between 2.1 bar and 3.2 bar, more preferably between 2.2 bar and 2.5 bar, even more preferably substantially around 2.3 bar.

16. The method according to any one of claims 12 to 15, wherein said second turbine body (5) comprises two expansion blocks with different isoenthropic efficiencies, wherein the first block expands steam in the superheated steam zone and the second block expands steam in the wet steam zone at high titles.

17. The method according to any one of claims 12 to 16, comprising providing a mixing condenser (7), fluid-dynamically placed downstream of said second turbine stage (5), said mixing condenser (7) being fluid-dynamically connected with cooling towers (9) and an AMIS type primary emission abatement system (15) or a system based on the absorption of non-condensable gases in water at high pressure between 30-40 bar in order to produce an increase in power while maintaining secondary emissions within tolerance limits.

18. The method according to any one of claims 12 to 17, wherein the steam component exiting said first expansion stage is first heated at a constant temperature up to the dry saturated steam conditions and then superheated.

19. The method according to any one of claims 12 to 18, wherein the wet steam component exiting said first expansion stage is first heated at a constant temperature up to the dry saturated steam conditions and then superheated by a regenerative process using part of the heat of the separated liquid component, the heating and superheating being performed in the same heat exchanger (3).