GB2539026A

GB2539026A - Geothermal steam processing

Info

Publication number: GB2539026A
Application number: GB1509705.8A
Authority: GB
Inventors: Gudmundsson Lárus; Bardarson Gestur; Magni Benediksson Sigurour; Einarsson Snorri
Original assignee: GREEN ENERGY GROUP AS
Current assignee: GREEN ENERGY GROUP AS
Priority date: 2015-06-04
Filing date: 2015-06-04
Publication date: 2016-12-07
Also published as: WO2016193700A1; GB201509705D0

Abstract

A steam processing system for a wellhead geothermal power plant 2 comprises a separator 8 for receiving a two-phase fluid from a geothermal well 4 that is arranged so as to separate steam from the two-phased fluid, an active heat exchanger 10 arranged to receive and condense the steam from the separator, and a demister 12 arranged to remove condensate from the processed steam. The heat exchanger 10 causes the steam to partially condense forming condensate. The formation of condensate removes contaminants carried by liquid in the steam. The condensate is then removed by the demister, taking with it most of the contaminants, to prevent build-up or damage to the turbine 16.

Description

Intellectual Property Office Application No. GII1509705.8 RTM Date:9 November 2015 The following terms are registered trade marks and should be read as such wherever they occur in this document: Mitsubishi (page 7) TEMA (page 15) ASME (page 16) Intellectual Property Office is an operating name of the Patent Office www.gov.uk /ipo -1 -Geothermal steam processing The present invention relates to the processing of working saturated steam in a wellhead geothermal power plant.

Wellhead geothermal power plants are becoming popular in the industry since they utilise saturated steam from only one or two wells at a time, thus avoiding the cost of constructing large power plants and steam transmission lines the saturated steam can be harnessed directly from the wellhead and the plant can be optimized for each individual well. By constructing one power plant for each well, lead times are significantly reduced and power can be harnessed from a new well within a year. Furthermore, traditional power plants gather steam from multiple wells, but are limited to wells within a 2-5 km radius from the plant due to the need to transport the steam; for wellhead geothermal power plants, there is no limit since the only lines connected to the power plant are power transmission lines.

The fluid coming from a geothermal well can be of three principal types: * Liquid-phase, low-temperature wells, which are liquid dominated wells that can have pressure above atmospheric; * Two-phase, high-temperature wells, which are wells that produce a two-phased fluid in liquid and vapour phases; and * Dry-steam, high-temperature wells, where the well is steam-dominated.

The well conditions are of great importance because the well pressure and fluid composition govern the output of the power plant. The wellhead power plant needs to adjust to the conditions of each well accordingly. An example of this is the Reykjanes power plant where the pressure cannot go below a specific limit because the total dissolved solids (TDS) is very high, and hence amorphous silica will precipitate and adhere to the surface equipment of the plant if the pressure is lowered, which can cause a shutdown if not handled correctly.

Most production wells are of the two-phase kind, although steam-dominated fields are not uncommon, such as the Geysers in California and at Reykjanes where the water level is low and boiling occurs in the reservoir causing a steam cap to be formed in the upper part of the reservoir.

Wellhead geothermal power plants typically work with two-phased fluid type wells and separate the fluid into steam and liquid (brine). The steam is used to -2 -power the turbine and the brine is re-injected back into the reservoir through reinjection wells, or is released via a silencer.

The separation process aims to remove as much liquid from the steam as possible. The quality and purity of the steam that the turbine processes is an important factor in producing power from a steam turbine. Usually the steam quality from the separators is at least 99.9% steam, but the quality of the steam is independent of its purity. Steam quality, often called the dryness fraction, is the mass fraction in a saturated mixture that is steam. Steam purity is a measure of the quantity of contaminants that are carried with the steam.

The present invention provides a steam processing system for a wellhead geothermal power plant, comprising: a separator for receiving a multi-phase fluid from a geothermal well and arranged so as to separate steam from the fluid; an active heat exchanger arranged to receive and partially condense the steam from the separator partially; and a demister arranged to receive processed steam from the separator and to remove condensate from the processed steam.

In the present context, it should be understood that the term "active heat exchanger" refers to a heat exchanger in which the degree of heat exchange can be controlled to achieve a desired rate of heat exchanger. Furthermore, in the present context, the term "wellhead geothermal power plant" refers to a geothermal power plant located proximate the wellhead, for example within 100m of the wellhead. Typically a wellhead geothermal power plant will be a dedicated power plant that generates power from a single well and might generate between 2.5 and 10 MW of power.

In accordance with the present invention, a heat exchanger is provided to process the steam for supply to a geothermal turbine of a wellhead. This has been found to improve the purity of the steam produced by the system.

Before wellhead geothermal power plants were used, the conventional way to harvest geothermal power was to drill multiple wells and gather the steam from all of the wells using a steam gathering system. The steam gathering station would bring the steam to a separator station, where the steam was separated from the liquid phase of a two-phased fluid, and the separated steam would then be piped to a power house which contained the turbine. It was undesirable to have long pipelines containing two-phased fluid due to the risk of slug flow. Instead, the steam and liquid would be separated as soon as possible, with the steam being transported as dry, saturated steam. -3 -

During transport, the steam would have heat and pressure loss proportional to the length of the pipeline and the materials used. As the pressure drops in the pipeline, for example due to frictional forces, elevation changes, bends and the roughness of the pipe, small liquid droplets within the steam start to boil and get smaller. Conversely, heat loss occurring due to the temperature difference the steam inside the pipe and the surrounding, would causes the steam to condense along the pipeline walls and accumulate in the bottom of the pipe.

Generally, more liquid would condense due to heat loss than would evaporate due to pressure drop and thus condensate would start to form. Drains for the condensate would be located at regular intervals along the pipeline to remove the condensate, or a demister could be used to remove the condensate. The formation of condensate was found to be advantageous because it dilutes unwanted constituents carried over from the separator by liquid in the steam. Such constituents can include silica, iron and chloride (SiO2, Fe and CI respectively), which can cause solid depositions on the turbine blades and within the turbine nozzle, and non-condensable gases (NCGs), such hydrogen sulphide and carbon dioxide, which can result in very acidic condensate that causes corrosion. The condensate can then be removed, taking with it some of the unwanted constitutes.

Thus, in conventional geothermal systems, the transport of the separated steam resulted in the purity of the steam being improved because the contaminants are present in the condensate that is then removed either by a drain or by a demister.

The present system provides a steam cleaning effect in a wellhead geothermal processing plant similar to that achieved in conventional geothermal plants. In particular, after separation of the bulk water from the multi-phase fluid extracted from the well, the described system allows a small proportion of the steam to be condensed (by the active heat exchanger) to dilute the liquid containing the contaminants, the diluted liquid is then removed (by the demister) to provide purer steam for supply to the turbine. This can significantly reduce the TDS concentration within the steam, resulting in reduced turbine scaling, which increases the life of the turbine as well as reducing maintenance and down time.

Put another way, to dilute the concentration of TDS from the separator, the active heat exchanger partially condenses the steam to increase the size of the droplets and capture smaller droplets. This effectively dilutes the concentration of -4 -TDS contained within the brine droplets. In the final stage, the larger droplets are removed by the demister, resulting in only small droplets containing a lower TDS concentration.

Secondly, by using an active heat exchanger, the described system provides the ability to accurately regulate the purity of the steam entering the turbine by adjusting the condensation rate of the steam. This allows optimisation of the processing for each well depending on its chemical composition or TDS amount. Such control would not have been appropriate in conventional geothermal processing where the different compositions between different production wells would have resulted in different compositions. Also, in the conventional system, the physical distance between the wellhead and the plant was the key dictator of the condensation rate..

Furthermore, the active heat exchanger allows the system to account for changes in ambient conditions, for example throughout the year, outdoor temperatures can easily fluctuate by more than 30-40°C.

Preferably, the heat exchanger is a forced-convection heat exchanger. Such a system is compact and mechanically simple, minimising cost and maintenance.

In one embodiment, the heat exchanger is a forced-induction heat exchanger. The advantage of an induced-draft heat exchanger is that the air distribution across the heat exchange tubes is more even, there is less potential for hot air recirculation due to the higher exit velocities, and there is less influence from weather conditions such as rain.

In another embodiment, the heat exchanger is a forced-draft heat exchanger. A forced-draft heat exchanger may be preferred since it is structurally simpler than an induced-draft heat exchanger. A forced-draft heat exchanger also has lower fan power requirements, due to lower air pressure at the colder side, it provides easier access for maintenance, and the fan and motor are not subjected to high temperatures.

As discussed above, the heat exchanger is an active heat exchanger and so would typically be expected to achieve higher heat exchange rates than the passive heat exchange occurring in the prior. Indeed, the heat exchanger preferably has a continuous (i.e. from inlet to outlet) heat exchange pipe length of below 50 metres and most preferably below 5 metres. In a preferred embodiment, the heat exchange pipe length of the heat exchanger in between 0.5 metres and 2 metres. -5 -

In various embodiments, the demister may comprise both chevrons and a mesh pad, so as to maximise the quantity of water extracted from the steam.

In a preferred aspect, the present invention provides a wellhead geothermal power plant installed close to a geothermal well and comprising a turbine and a steam processing system as described above. The separator may be arranged to receive a multi-phase fluid from the geothermal well, and the turbine may be arranged to receive steam from the demister.

Typically, for this application, the separator would be designed to provide output steam having a quality of at least 99.9%.

Viewed from another aspect, the present invention provides a method of processing steam for a wellhead geothermal power plant, comprising: separating steam from a multi-phase fluid from a geothermal well; partially condensing the separated steam using an active heat exchanger such that a condensate forms; and removing the condensate from the partially-condensed steam to produce purified, dry steam.

As discussed above in respect of the apparatus, this method advantageously purifies the steam, as well as providing improved control of the process to optimise the steam purity based on wellhead and ambient conditions. As discussed above, the heat exchanger may a forced-convection heat exchanger, and may be either a forced-draft heat exchanger or a forced-induction heat exchanger.

Preferably the steam quality from the separator is at least 99.9%, and more preferably at least 99.95%. Furthermore, after partial condensation, the steam preferably has a quality of below 99.9%, and preferably below 99.85%. The steam is preferably cooled by the heat exchanger sufficiently to achieve a reduction in steam quality of between 0.15% and 1.0%.

A typical steam quality from the separator is from 99,9% to 99,99%, and by condensing the steam partially by 0,15% to a maximum of 1,0% steam quality, the TDS concentration in the carryover droplets from the separator can be reduced theoretically by upwards of 10 folds. The condensate produced by the process is then removed by a demister.

In various embodiments, the pressure difference between the separated steam and the purified, dry steam may be between 0.05 and 0.2 bar. -6 -

In another aspect, the present invention provides a method of operating a wellhead geothermal plant comprising: processing steam by the method described above; and extracting energy from the purified, dry steam using a turbine.

Preferably the separated steam is introduced to a turbulent situation such that the condensate is mixed with liquid carried over from the separator. In one embodiment, the heat exchanger is configured so as to generate vortexes in the outlet header, for example by injecting steam from heat exchange tubes into the outlet header along a tangent that is radially offset from an axis of the outlet header. The steam is directed into the outer header where it is subjected to centrifugal forces due to the inlet being along a tangent and radially offset from the axis of the outlet header; the larger droplets have higher momentum than the smaller and seek towards the pipe wall due to the centrifugal forces. This causes the condensate to be mixed to a degree as it moves in circular direction in the outer header and converges with the other steam inlets in the outer header. The air cooled heat exchanger introduces the flow to high vorticity which will prove to increase the heat transfer and fluid mixing as condensation occurs.

Certain preferred embodiments of the present invention will now be described in greater detail, by way of example only and with reference to the accompanying figures, in which: Figure 1 shows a wellhead geothermal power plant; Figure 2 is a side view of a horizontal separator; Figure 3 is a side view of a vertical separator; Figure 4 is a plan view of a heat exchanger; Figure 5 is a side view of a first arrangement of the heat exchanger; and Figure 6 is a side view of a second arrangement of the heat exchanger.

The following embodiments relate to a wellhead geothermal power plant 2, such as shown in Figure 1, for extracting power from fluid extracted from a geothermal production well 4. By way of example, the wellhead geothermal plant manufactured by the Norwegian company Green Energy Group AS generate output power in the range of 3.2 MW to 6.4 MW per plant. The wellhead geothermal power plant 2 in Figure 1 extracts power from a single production well 4, although some wellhead geothermal power plants can extract power from two or more production wells located within close proximity to one another.

The wellhead geothermal power plant 2 comprises an input line 6 for receiving a two-phase fluid from the geothermal production well 4. The input line -7 -connects to a separator 8 for separating steam from the two-phase fluid. The separated steam is output from the separator to a heat exchanger 10, which extracts heat from the steam to cause condensation. The processed steam from the heat exchanger 10 is then dried by a demister 12, which removes most of the condensate from the processed steam (typical design specifications require a minimum dryness of at least 99.9%). The dried steam is then output from the demister 12 to an output line 14 for supply to a turbine 16 where energy is extracted from the steam.

Fouling or scaling is a common problem in the geothermal industry. Once the steam has been separated from the two-phase fluid, the scaling is minimal compared to the brine side, but scaling can happen in the turbine, as the pressure drops causes any liquid droplets to evaporate and deposit dissolved solids. Thus, the problem of scaling is most prevalent in the two-phase inlet line 6 (i.e. before reaching the separator 8), in the brine outlet (not shown) from the separator 8, and in the first few stages of the turbine 16.

Scale within the turbine 16 can carry high costs in regards to maintenance and life time of the turbine 16. Turbine manufacturers are observant of this problem as table 1 below shows (an extract from the Mitsubishi Turbine Operating Manual defining maximum content of impurities).

Table 1:

vihes Seemgrio Scenario.2 Scenario :rcAt.j.).1 H,7 <E03E Sokate: Operaii nuai Alt ^,-sctries, sr.-. in rim tnip.1? ) The scenario modes referenced in Table 1 are the following: * Scenario 1: Continuous normal operation with minimum maintenance.

* Scenario 2: Abnormal operation, requires regular maintenance.

* Scenario 3: The turbine should not be operated. In one example, a well operating with 0.1 ppm silica and 15 ppm total dissolved solid (TDS) would not be ideal but would be allowable and should not -8 -require maintenance until 2 years of operation, with around 10% power loss after two years. A well operating at the upper limit of 1.0 ppm silica and 50 ppm TDS would result in roughly 20% power loss in one year, requiring vast maintenance. Thus, by reducing the TDS concentration in the water droplets that enter the turbine 16, the life of the turbine can be improved and maintenance and downtime of the turbine 16 can be minimised.

The steam processing system (comprising the separator 8, heat exchanger 10, and demister 12) cleans the steam and can reduce the TDS concentration by approximately a factor of 10 theoretically, which greatly reduces the potential of scaling. To achieve this, the steam is partially condensed using active heat exchange by the heat exchanger 10, as depicted in Figures 2 to 4. By using forced air convection, such as by using fan(s), the process can be controlled to a greater extent than prior art systems relying on passive heat loss, since the heat losses in such systems were highly dependent upon outside air conditions.

The process of steam cleaning causes a small pressure loss and a very small mass flow reduction, however these losses are minimal compared to the gains from being able to continuously operate the turbine 16.

Separator The separation process is essential to remove as much liquid from the steam as possible. The received steam quality varies between locations and the composition of the well. However, usually geothermal applications require the steam quality from a separator 8 to be at least 99.9%. Two main types of separator 8, 8' are used for geothermal steam processing and Figures 2 and 3, respectively, show a horizontal type separator 8 and a vertical type separator 8'.

The horizontal type separators 8 use gravity to separate the two-phased fluid within a separation chamber 30. When the fluid enters the separation chamber 30 via an inlet 32, the liquid droplets settle in the tank 30 due to gravity forces. The steam is extracted at a steam outlet 34 located at the top of the chamber 30 at an end of the chamber 30 opposite to its inlet. The liquid (brine) is removed via a brine outlet 36 at the bottom of the chamber 30.

Typically, flow distributors such as baffle plates or diffusers will be arranged adjacent the inlet 32 and typically there are wire meshes or guide vanes (chevrons) positioned adjacent the steam outlet 34 to trap any larger liquid droplets. -9 -

The vertical the separator 8', uses centrifugal force to separate the liquid from the steam. The fluid is injected into a vertically cylindrical separator tank 30' along a circumferential path from a steam inlet 32'. The heavier water droplets adhere to the walls of the cylindrical tank 30' due to high momentum and surface tension and fall out of brine outlet 36'. The steam is extracted via a steam outlet 34' in the form of a pipe that runs along the centre of the cylinder and opens at the top of the chamber 30'.

Heat exchanger There are many types of heat exchanger 10, but the most type common for air cooled operations is a cross-flow shell heat exchanger 10, as illustrated in Figures 4 to 6. Figures 5 and 6 illustrate two alternative fan configurations for the heat exchanger 10, 10'.

The heat exchanger 10 comprises a front end header 18 comprising a channel having a removable cover plate to allow maintenance and to allow viewing of the interior of the heat exchanger 10 to determine scaling, erosion or corrosion. Attached to the front header 18 is a plurality of first heat exchange tubes 20 through which the steam flows and is cooled and thus partially condensed. Air is forced across these heat exchange tubes 20 by one or more fans 22 to partially condense the fluid within the tubes 20 in a controlled manner.

Attached to the other end of the tubes 20 is a second header 24. In this embodiment, the second header 24 is a floating header that directs the fluid from the plurality of first heat exchange tubes 20 to a plurality of second heat exchange tubes 26. These run parallel and opposite to the first heat exchange tubes 20.

It will be appreciated that the second heat exchange tubes 26 are optional and that the second header 24 may be configured to achieve mixing such that the heat exchanger 10 it is a one pass heat exchanger.

The heat exchanger 10 is preferably configured to operate in the turbulent regime, for example by introducing vortexes in the tube banks 20, 26, in the second header 24, or in an outlet header). This mode of operation improves heat exchange and mixes the condensate with liquid carryover from the separator to catch any small droplets carried over.

Figures 5 and 6 show two alternative types of heat exchanger 10, 10' comprising substantially horizontal heat exchange tubes 20, 26. Figure 5 shows a forced-draft type of heat exchanger 10 and Figure6 shows an induced-draft type of heat exchanger 10'.

A forced-draft heat exchanger 10 is often preferred since it is structurally simpler than an induced-draft heat exchanger 10'. Some of the benefits of using a forced-draft heat exchanger 10 are that it has lower fan power requirements, due to lower air pressure at the colder side, it provides easier access for maintenance, and the fan is not subjected to high temperatures.

The advantages of an induced-draft heat exchanger 10' is that the air distribution across the heat exchange tubes 20, 26 is more even, there is less potential for hot air recirculation due to the higher exit velocities, and there is less influence from weather conditions such as rain.

The effectiveness of a heat exchanger 10 depends on the fluid and the surface area that fluid comes into contact with; the heat is transferred from the hot fluid (the steam) to the cold fluid (the air). Mediums such as air have low conductivity, and therefore by increasing the surface area that the air comes into contact with, the efficiency of the heat exchanger can be improved. The heat exchange tubes 20, 26 of the heat exchanger are therefore provided with extended surface covered, such as a helical fin. Such fins may be serrated or non-serrated.

The fins may be high frequency welded on to the pipe to minimize the heat-affected zone after the weld. Various methods exist to fasten fins to the pipe, and various materials can be bonded together for this purpose, for example aluminium and steel may be bonded together by milling grooves into the external surface of a steel pipe wall, placing an aluminium sheet into the groove, and then crumpling the steel around the aluminium sheet to hold it in place.

Due to the different metals the thermal expansion is different and by choosing the same material, such as carbon steel tubing to carbon steel fins, the risk of failing can be reduced. In the preferred embodiment, carbon steel is used for both the heat exchange tubes 20, 26 and the fins. Carbon steel has been found to be cost effective and least prone to mechanical failure.

It has further been found that relatively radially-short fins (between 10% and 25% of the radius of the tubes) on the heat exchange tubes 20, 26 provide optimal heat exchange. This is because the thermal conductivity of carbon steel is relatively low and thus increasing the height of the fin reduces the fin efficiency by not utilising the fins to their full potential. By maximizing the thermal transfer for the fins and minimizing the fan work required, taking into account the width of the unit, an optimized size was selected as the base scenario. The results showed a relatively good thermal heat transfer and minimal work required by the fan.

Demister The demister 12 is arranged to remove moisture droplets in the steam using either or both of chevrons and wire mesh pads. Saturated vapour enters a demister chamber where it gathers and is forced through the chevrons, mesh pads or both, which results in removal of liquid droplets contained within the steam.

Chevrons utilise "inertial impaction", which is where heavy droplets travel through vanes and are pushed to the walls due to their momentum. Some designs incorporate a "hook", where the vanes contain a curved lip extending outwards from the tips of the vanes and capture more droplets. Chevrons are well suited for high velocity steam containing relatively large droplets to remove the droplets.

Wire mesh pads comprise a net of wires that capture the droplets as they pass through. These pads operate more effectively at lower velocities than chevrons and are well suited to capturing small droplets. However, liquid entrainment can be a problem if the steam contains higher quantities of liquid, which can result in liquid passing through the pads.

Often, mesh pads are used in combination with chevrons with the mesh pads being provided downstream of the chevrons to remove the smaller droplets not captured by the chevrons.

Various designs of demister 12 are used in the geothermal industry and those of ordinary skill in the art will be familiar with these. Different designs of demister 12 suite various purposes and would be selected accordingly. However, common values for the quality of steam exiting a demister 12 would be from approximately 99.99% to approximately 99.999%.

Examples

The following description sets out details of specific parameters that may be used for the heat exchanger 10.

Analytical Model First, an analytical model of the heat exchanger 10 was built to determine various factors, such as how fan face velocity affects the condensation rate within the heat exchanger, amongst others.

The model took into account the following parameters: * Elevation changes / atmospheric pressure.

* Steam properties entering the heat exchanger 10.

* Geometry of the finned tubes 20, 26, number of tubes 20, 26 and number of rows of tubes 20, 26.

* Material properties of the tubes 20, 26, such as conductivity, fouling and wall roughness.

* Condensation due to thermal losses and evaporation due to pressure losses.

* Outside conditions such as relative humidity and temperature.

* Steam purity entering the turbine 16, with and without the heat exchanger 10, given the TDS from the separator 8.

* Sizing and power consumption of the fan 22.

The model was bound by limits, such as for fin height, thickness, number of fins and the Reynolds number. The initial conditions that were set for the model are

given in Table 2.

Table 2: Heat exchanger initial conditions and assumptions 401cdeac.y TOP' pnye:yth,s, Ther1n10 conductivii..A.wrage wail, i0.1kattmss nt1agctiffier041 s.-thir.tv fia0tor Irgeit:M WIteiit: op

I

is fixter 350 3:12-1<Th s SA. 40 pacing :MO --atincf4p}.7404,-;r0t.:81= 3304a n, flaw TDS ia:Ix separator triternai ppc,!;s3.3.re cfrw, In the model, the following assumptions were made: * Air flow across the tubes is uniform.

* NCG gas is considered inert and is not accounted for.

* No air recirculation at the fan outlet.

* No heat loss from the header to the environment.

First the differences between serrated and solid fins were considered for varying face velocities. It was found that the difference between the work performed by the fan for serrated or solid fins was so small that it could considered to be the same for either fin configurations. The parameters used for the test are

set out in table 3.

Table 3: Ranges for the changing variables and the initial (base) values If.0.x:fbt To consider the capabilities of the heat exchanger further the model was run for two different design scenarios. Scenario A was the maximum temperature for a given location (an outside temperature of 30°C and a fan face velocity of 4 m/s), and Scenario B was a very cold scenario (an outside temperature of 0°C and a fan face velocity of 2.5 m/s). The face velocities were selected from common face velocities; face velocities of 1.5 -3.6 m/s are common and a 4 m/s face velocity, as in Scenario A, is the worst case Due to the multi-variable options in the model, the only those variables listed in Table 3 were changed.

Scenario A: Table 4 illustrates the operating conditions of the system 2 when operated so as to achieve an outlet steam quality of 99.999% from the demister 12.

&Ifiatkityti :,,cenario ikariable' 0)0C 0 Table 4: Conditions under Scenario A Sertaed TDS ktrottit.t.coriceatrtufett' tYt DS drc...titiet Ittlo the rACR 4 7 ppm lil t The results of the tests performed under Scenario A are shown in Figures 7 to 11.

Fin height: Figure 7A and 7B shows how the thermal transfer and fan work changes with changing fin height. It is noted that the transverse tube pitch is directly related to the fin height through fin spacing variable.

Fin thickness: Figure 8A and 8B show how the fin thickness affects the thermal transfer: the thicker the fin the more heat is transferred due to conductivity.

The outside surface area of the heat exchanger 10 is increased by increasing fin thickness, which results in more heat being transferred. There is a slight increase in the fan work but it is insignificant.

Fins per meter: Figures 9A and 9B show that the fins per meter factor is one of the most important factors as it can increase the thermal transfer rate by more than two folds, but it also increases the power the fan needs due to the increased static pressure drop across the tubes 20, 26. Another effect of having increased fins per meter is fouling and cleaning because very tightly packed fins have a tendency to capture small dust particles which cluster together, thereby decreasing the performance of the heat exchanger 10 via external fouling.

Fin spacing: Fin spacing refers to how far the end of one fin is from the fin on the adjacent tube 20, 26. From Figure 10A and 10B it can be seen that the work done by the fan 22 is reduced by increased fin spacing; the reason for this is that the fin spacing is directly related to the spacing between the tubes. Thus, when the fin spacing is small, the distance between the tubes is also small resulting in high static pressure drop across the bundle.

Thertnal transfer 56.568.-W 547 Parasitic ktad law, .t Tcmp, vu, 1,NITD OxIclensAt SlVara cluai tv imp 1):,/ 7 Pp Fouling factors: Figures 11A and 11B indicate how fast fouling affects the thermal transfer of the heat exchanger 10. As depicted by the Figures, the internal fouling factor has a significantly steeper slope than the external factor, corresponding to a faster decrease of performance of the heat exchanger 10. The fouling factor is based on the TEMA standards for fouling.

Scenario B: Table 5 illustrates the operating conditions of the system 2 when operated so as to achieve an outlet steam quality of 99.999% from the demister 12. The results from Scenario B are shown in Figures 12 to 16 in the same way as Scenario A was shown in Figures 7 to 11.

There is minimal difference between the operating conditions and test results for Scenario A and B because of the fan velocities selected for the two scenarios; the fan 22 controls the condensation rate of the steam. This is significant because previous systems relying on passive condensation could not operate in a consistent manner when outside temperatures varied. When using this system 2, the most important factor for determining the geometry of the heat exchanger 10 is to know the highs and lows of the temperature variations at the site in which the system will be located.

Table 5: Conditions under Scenario B oJnt:ratcc.12 r)s IDS divii=ict 172,WC

W

From the analytical model shorter fins on the tubes were found to serve best because the thermal conductivity of carbon steel is relatively low. By increasing the height of the fin, the fin efficiency is reduced and thus the system does not utilise the fins to their full potential. By maximizing the thermal transfer for the fins and minimizing the fan work required, taking into account the width of the heat exchanger 10, an optimized size can be selected based on the requirements of the heat exchanger 10. The results showed a relatively good thermal heat transfer could be achieved with minimal work required by the fan 22.

As demonstrated by this model, for Scenario A, the initial quality of the steam from the separator 8 is 99.99% and the quality leaving the heat exchanger 10, including the pressure drop, is 99.836% ± 0,015% for the serrated fins and 99.841% ± 0.015% for the solid fins. This lower quality of steam equates to a greater proportion of condensate, resulting in significant dilution of the TDS (assuming all TDS is entrapped in the liquid).

CDF Model Next, four different heat exchanger designs were analysed using CFD software to determine the pressure drop inside the heat exchanger due to the irregular geometry.

* Design 1 (shown in Figure 17A) comprises a 14" (-36 cm) diameter inlet pipe connected to an inlet header, a tube bank of 5" (-13 cm) diameter tubes extending from the inlet header, and a 14" (-36 cm) diameter outlet tube connected tangential to the tube bank acting as an outlet header.

* Design 2 (shown in Figure 17B) is the same as Design 1, except that the inlet header has been extended by 2 cm in all directions and the outlet header diameter has been enlarged to 16" (-41 cm) with a reducer connecting it to the 14" (-36 cm) diameter outlet pipe.

* Design 3 (shown in Figure 17C) is the same as Design 2, but includes two 7" (-18 cm) diameter outlet pipes with a reducer from the outlet header to each outlet pipe.

* Design 4 (shown in Figure 17D) is the same as Design 2 but with a differently-shaped inlet header.

The four design was made as standardized as possible; the front header was designed to API Standard 661/ISO 13706:2001 and the flanges were ASME B16.5 flanges class 150 flanges, although for more safety class 300 flanges could have been adopted.

In the CDF model, two turbulence models were compared: the k-i and the SST k-co models. The SST k-w turbulence model captures how the flow behaves in the boundary layers more accurately, which is an important factor when analysing pressure drop. However, the k-E also worked well for determining pressure drop, as the results show. The results of the CDF model are shown in Table 6.

Table 6: CDF model pressure drop Design 9. tkr*.

The CFD analysis was used to determine the pressure loss through the device by analysing different designs and using two very common turbulence models, from which the results show very similar pressure drop in most cases. It is possible to deduct, to some degree of certainty, that the average pressure loss would be 0.11 bara for a steady state operation.

A significant feature of the exemplary designs, which could be observed during CFD analysis, was the formation of large vortex swirls produced in the tube banks and in the outlet header. As the flow entered the first header, the flow was divided and the intensity of the flow entering the tubes resulted in vortexes forming such that the profile velocity was highly distorted and the flow adhered to the tube walls. Furthermore, the outlet header acted similarly to a centrifuge by forcing the condensed droplets to adhere to the walls of the header due their momentum. The intensity of the vortex that occurs in the outlet header ensures proper mixing of the steam, thereby resulting in properly mixed condensate that has been fully diluted.

Conclusion

In the preferred embodiment, the described system 2 cleans the steam by diluting the TDS concentration by ten-fold theoretically and then removing the diluted liquid. By utilizing a heat exchanger 10 that is located prior the steam entering the turbine 16, the condensation rate of the steam can be controlled and

SST

K-7 press, 2.056 710,093 89...2.150 8R 96 I 3.448 12907..",:. 1470,4.4 optimized for each well depending on its chemical composition or TDS amount. This is of great benefit for turbine operators due to reduce the possibility of scaling. The downside is increased pressure loss to the turbine and a very small mass flow reduction; however, these downsides are minimal compared to continuous operation of the turbine -every hour that the turbine is offline is a loss regarding electricity generation. The possibility of diluting the TDS in the condensate in the manner described above has been found to be a very viable option.

Claims

CLAIMS: 1. A steam processing system for a wellhead geothermal power plant, comprising: a separator for receiving a multi-phase fluid from a geothermal well, the separator being arranged to separate steam from the multi-phase fluid; an active heat exchanger arranged to receive and partially condense the steam from the separator; and a demister arranged to receive processed steam from the heat exchanger and to remove condensate from the processed steam.
2. A steam processing system according to claim 1, wherein the heat exchanger is a forced-convection heat exchanger.
3. A steam processing system according to claim 2, wherein the heat exchanger is a forced-draft heat exchanger.
4. A steam processing system according to claim 2, wherein the heat exchanger is a forced-induction heat exchanger.
5. A steam processing system according to any preceding claim, wherein the heat exchanger has a continuous pipe length of below 50 metres and preferably below 5 metres.
6. A steam processing system according to any preceding claim, wherein the demister comprises chevrons and/or a mesh pad.
7. A steam processing system according to any preceding claim, wherein the separator is sized to output steam having a quality of at least 99.9%, and the heat exchanger is configured to condense the steam to a quality of below 99.85%.
8. A wellhead geothermal power plant installed above a geothermal well and comprising a turbine and a steam processing system according to any preceding claim, wherein the separator is arranged to receive a multi-phase fluid from the geothermal well, and wherein the turbine is arranged to receive the steam from the demister of the steam processing system.
9. A method of processing steam for a wellhead geothermal power plant, comprising: separating steam from a multi-phase fluid from a geothermal well; partially condensing the separated steam using an active heat exchanger such that a condensate forms; and removing the condensate from the partially-condensed steam to produce purified, dry steam.
10. A method according to claim 9, wherein the heat exchanger is a forced-convection heat exchanger.
11. A method according to claim 10, wherein the heat exchanger is a forced-draft heat exchanger.
12. A method according to claim 10, wherein the heat exchanger is a forced-induction heat exchanger.
13. A method according to any of claims 10 to 12, wherein the separated steam has a quality of at least 99.9%, preferably at least 99.95% and more preferably at least 99.99%.
14. A method according to claim 13, wherein the steam has a quality of below 99.9% after condensing, and preferably below 99.85%.
15. A method according to any of claims 9 to 14, wherein the steam is condensed by the heat exchanger sufficiently to achieve a reduction in saturated steam quality between 0.15% and 1.0%.
16. A method according to any of claims 9 to 14, wherein the separated steam is condensed sufficiently to reduce the total dissolved solids within the steam by at least 80%, and preferably at least 90%.

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17. A method according to any of claims 9 to 16, wherein the pressure difference between the separated steam and the purified, dry steam is between 0.05 and 0.2 bar.
18. A method according to any of claims 9 to 17, wherein the separated steam is introduce to a turbulent situation such that the condensate is mixed with liquid carried over from the separator.
19. A method of operating a wellhead geothermal plant comprising: processing steam by the method of any of claims 9 to 18; and extracting energy from the purified, dry steam using a turbine.
20. A steam processing system for a wellhead geothermal power plant substantially as hereinbefore described with reference to the drawings.
21. A method of processing steam for a wellhead geothermal power plant substantially as hereinbefore described with reference to the drawings.