WO2016193700A1 - Traitement de vapeur géothermique - Google Patents

Traitement de vapeur géothermique Download PDF

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Publication number
WO2016193700A1
WO2016193700A1 PCT/GB2016/051580 GB2016051580W WO2016193700A1 WO 2016193700 A1 WO2016193700 A1 WO 2016193700A1 GB 2016051580 W GB2016051580 W GB 2016051580W WO 2016193700 A1 WO2016193700 A1 WO 2016193700A1
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WO
WIPO (PCT)
Prior art keywords
steam
heat exchanger
separator
wellhead
geothermal
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Application number
PCT/GB2016/051580
Other languages
English (en)
Inventor
Lárus GUÐMUNDSSON
Gestur BÁRÐARSON
Sigurður Magni BENEDIKSSON
Snorri EINARSSON
Original Assignee
Green Energy Geothermal Uk Limited
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Publication date
Application filed by Green Energy Geothermal Uk Limited filed Critical Green Energy Geothermal Uk Limited
Publication of WO2016193700A1 publication Critical patent/WO2016193700A1/fr

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Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F28—HEAT EXCHANGE IN GENERAL
    • F28B—STEAM OR VAPOUR CONDENSERS
    • F28B1/00—Condensers in which the steam or vapour is separate from the cooling medium by walls, e.g. surface condenser
    • F28B1/06—Condensers in which the steam or vapour is separate from the cooling medium by walls, e.g. surface condenser using air or other gas as the cooling medium
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01K—STEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
    • F01K7/00—Steam engine plants characterised by the use of specific types of engine; Plants or engines characterised by their use of special steam systems, cycles or processes; Control means specially adapted for such systems, cycles or processes; Use of withdrawn or exhaust steam for feed-water heating
    • F01K7/16—Steam engine plants characterised by the use of specific types of engine; Plants or engines characterised by their use of special steam systems, cycles or processes; Control means specially adapted for such systems, cycles or processes; Use of withdrawn or exhaust steam for feed-water heating the engines being only of turbine type
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B1/00—Methods of steam generation characterised by form of heating method
    • F22B1/02—Methods of steam generation characterised by form of heating method by exploitation of the heat content of hot heat carriers
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B37/00—Component parts or details of steam boilers
    • F22B37/02—Component parts or details of steam boilers applicable to more than one kind or type of steam boiler
    • F22B37/26—Steam-separating arrangements
    • F22B37/265—Apparatus for washing and purifying steam
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B37/00—Component parts or details of steam boilers
    • F22B37/02—Component parts or details of steam boilers applicable to more than one kind or type of steam boiler
    • F22B37/26—Steam-separating arrangements
    • F22B37/32—Steam-separating arrangements using centrifugal force
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F24—HEATING; RANGES; VENTILATING
    • F24T—GEOTHERMAL COLLECTORS; GEOTHERMAL SYSTEMS
    • F24T10/00—Geothermal collectors
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F24—HEATING; RANGES; VENTILATING
    • F24T—GEOTHERMAL COLLECTORS; GEOTHERMAL SYSTEMS
    • F24T10/00—Geothermal collectors
    • F24T10/20—Geothermal collectors using underground water as working fluid; using working fluid injected directly into the ground, e.g. using injection wells and recovery wells
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F24—HEATING; RANGES; VENTILATING
    • F24T—GEOTHERMAL COLLECTORS; GEOTHERMAL SYSTEMS
    • F24T10/00—Geothermal collectors
    • F24T10/30—Geothermal collectors using underground reservoirs for accumulating working fluids or intermediate fluids
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F28—HEAT EXCHANGE IN GENERAL
    • F28F—DETAILS OF HEAT-EXCHANGE AND HEAT-TRANSFER APPARATUS, OF GENERAL APPLICATION
    • F28F1/00—Tubular elements; Assemblies of tubular elements
    • F28F1/10—Tubular elements and assemblies thereof with means for increasing heat-transfer area, e.g. with fins, with projections, with recesses
    • F28F1/12—Tubular elements and assemblies thereof with means for increasing heat-transfer area, e.g. with fins, with projections, with recesses the means being only outside the tubular element
    • F28F1/24—Tubular elements and assemblies thereof with means for increasing heat-transfer area, e.g. with fins, with projections, with recesses the means being only outside the tubular element and extending transversely
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F28—HEAT EXCHANGE IN GENERAL
    • F28F—DETAILS OF HEAT-EXCHANGE AND HEAT-TRANSFER APPARATUS, OF GENERAL APPLICATION
    • F28F2200/00—Prediction; Simulation; Testing
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E10/00—Energy generation through renewable energy sources
    • Y02E10/10—Geothermal energy

Definitions

  • 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.
  • the saturated steam can be harnessed directly from the wellhead and the plant can be optimized for each individual well.
  • lead times are significantly reduced and power can be harnessed from a new well within a year.
  • 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;
  • 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.
  • TDS total dissolved solids
  • 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 power the turbine and the brine is re-injected back into the reservoir through reinjection wei!s, 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.
  • 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.
  • 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.
  • wellhead geothermal power plant refers to a geothermal power plant located proximate the wellhead, for example within 100m of the wellhead.
  • 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 25 MW of power. In more common arrangements, a wellhead geothermal power plant may generate between 2.5 and 10 MW.
  • 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.
  • 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.
  • the steam 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 wails and accumulate in the bottom of the pipe.
  • 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.
  • condensate was found to be advantageous because it dilutes unwanted constituents carried over from the separator by liquid in the steam.
  • constituents can include silica, iron and chloride (Si0 2 , Fe and CI
  • NCGs non-condensable gases
  • the present system provides a steam cleaning effect in a wellhead geothermal processing plant similar to that achieved in conventional geothermal plants.
  • 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.
  • the active heat exchanger partially condenses the steam to increase the size of the droplets and capture smaller droplets. This effectiveiy dilutes the concentration of 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.
  • 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 possible in conventional geothermal processing where the physical distance between the wellhead and the plant was the key dictator of the condensation rate.
  • 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.
  • the heat exchanger may be an air-cooled heat exchanger, which is preferably configured to exchange heat with ambient air to partially condense the steam.
  • the heat exchanger is a forced-convection heat exchanger.
  • the heat exchanger may be an induced-draft (or forced- induction) heat exchanger, i.e. where the cooling fluid is drawn through the heat exchanger.
  • induced-draft or forced- induction
  • 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.
  • the heat exchanger may be a forced-draft heat exchanger, i.e. where the cooling fluid is driven through the 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.
  • 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.
  • 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.
  • the heat exchanger preferably comprises an inlet header and an outlet header connected by at least one heat exchange tube, and preferably by a plurality of heat exchange tubes.
  • the inlet header may be configured to receive the steam from the separator and the outlet header may be configured to direct the partially condensed steam to the demister.
  • the outlet header is preferably configured to mix the flow of partially condensed steam from the plurality of heat exchange tubes.
  • the inlet header and/or the outlet header may comprise a removable cover plate to allow maintenance and to allow viewing of its interior, for example to determine scaling, erosion or corrosion.
  • the heat exchange tubes may be formed from any suitable, thermally conductive material.
  • the heat exchange tubes are formed from carbon steel.
  • At least one fan is provided adjacent the plurality of tubes to move air past the tubes, for example as either an induced draft or as a forced draft, so as to partially condense the steam in a controlled manner.
  • the fan is preferably capable of generating a face velocity of between 1.5 and 4 m/s.
  • the heat exchanger may be configured as a multi-pass heat exchanger.
  • the heat exchanger may comprise one (or more) intermediate header between the inlet header and the outlet header.
  • the intermediate header may be configured to receive the steam from the inlet header via a first plurality of the heat exchange tubes and to direct the steam to the outlet header via a second plurality the of heat exchange tubes.
  • the intermediate header may be configured to mix the steam from the first plurality of the heat exchange tubes.
  • the second plurality of heat exchange tubes may run parallel and opposite to the first plurality of the heat exchange tubes.
  • a single fan or bank of fans can pass air through both pluralities of heat exchange tubes.
  • the fan(s) and heat exchange tubes are preferably configured such that the air passes the cooler, second plurality of the heat exchange tubes before passing the hotter, first plurality of the heat exchange tubes, i.e. in a counter-flow heat exchange configuration.
  • the heat exchanger may be preferably configured to operate in the turbulent flow regime.
  • one or more of the heat exchange tube(s), the inlet header, the outlet header and the intermediate header (where present) may be configured to introduce vortexes in the steam flowing through the heat exchanger. Turbulent flow improves heat exchange and mixes the condensate with liquid carryover from the separator to catch any small droplets carried over.
  • the outlet header is configured to receive injected steam from the heat exchange tubes along a tangent that is radially offset from a central axis of the outlet header.
  • the steam directed into the outer header is then subjected to centrifugal forces due to the inlet being along a tangent and radially offset from the axis of the outlet header.
  • One or more or each of the heat exchange tubes may include at least one mixing element therein to promote turbulent flow of the steam. That is to say, the tube(s) may be configured to operate as static mixers.
  • the tube(s) may include one or more twisted tape element(s) or the like.
  • the heat exchange tubes may be provided with external heat exchange projections.
  • the projections may include plates, fins, pins or the like. Most preferably the projections are in the form of a helical fin. Such fins may be either serrated or non-serrated. The fins preferably have a length of between 10% and 25% of the radius of the respective tube.
  • the demister may comprise one or both of chevrons and a mesh pad, so as to maximise the quantity of water extracted from the steam.
  • the separator may comprise either a horizontal type separator or a vertical type separator.
  • the separator preferably comprises a multi-phase inlet, a liquid outlet and a steam outlet.
  • the separator may comprise flow distributors, such as baffle plates or diffusers, which may be arranged adjacent the inlet to trap any larger liquid droplets.
  • the separator may comprise wire meshes and/or guide vanes (or chevrons) positioned adjacent the steam outlet.
  • the present invention provides a wellhead geotherma! power plant installed proximate (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 geotherma! well, and the turbine may be arranged to receive steam from the demister.
  • the wellhead geotherma! plant is preferably located on a well pad of the geothermal wellhead.
  • the well pad may have an area of less than 50,000m 2 , and preferably less than 20,000 m 2 .
  • the well pad may be a single well pad.
  • the wellhead geothermal plant is preferably configured to receive a multiphase fluid from a wellhead of a geothermal well and to pass the multi-phase fluid to the separator.
  • the plant is preferably located within 100m of the wellhead.
  • the wellhead geothermal plant may be configured to generate between 2.5 and 25 MW of power, and more preferably between 2.5 and 10 MW.
  • the separator is preferably designed to provide output steam having a quality of at least 99.9%.
  • the demister is preferably designed to provide output steam having a quality of at least 99.99%
  • 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.
  • the heat exchanger may a forced-convection heat exchanger, and may be either a forced-draft heat exchanger or a forced-induction heat exchanger.
  • 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. ln various embodiments, the pressure difference between the separated steam and the purified, dry steam may be between 0.05 and 0.5 bar, and preferably between 0.05 and 0.2 bar.
  • the present invention provides a method of operating a wellhead geothermai plant comprising: processing steam by the method described above; and extracting energy from the purified, dry steam using a turbine.
  • the separated steam is introduced to a turbulent situation such that the condensate is mixed with liquid carried over from the separator.
  • the heat exchanger is configured so as to generate vortexes in an outlet header thereof, 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.
  • Figure 1 is a schematic diagram of a wellhead geothermai 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
  • Figure 6 is a side view of a second arrangement of the heat exchanger
  • FIGS 7 to 16 graphically illustrate data representing how the thermal transfer rate and fan work of the heat exchanger vary as various physical properties of the heat exchanger are varied.
  • Figures 17A to 17D are perspective views of alternative designs for the heat exchanger.
  • the following embodiments relate to a wellhead geothermai power plant 2, such as shown in Figure 1 , for extracting power from fluid extracted from a geotherma! production well 4.
  • a wellhead geothermai power plant 2 such as shown in Figure 1
  • the wellhead geothermal plants manufactured by the UK company Green Energy Geothermal UK Limited 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 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 still happen in the turbine where the pressure drop 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.
  • Scenario 2 Abnormal operation, requires regular maintenance.
  • Scenario 3 The turbine should not be operated.
  • 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 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.
  • 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.
  • the steam is partially condensed using active heat exchange by the heat exchanger 10, as depicted in Figures 2 to 4.
  • 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 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.
  • 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.
  • 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 38 at the bottom of the chamber 30.
  • 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.
  • the vertical 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 38'.
  • 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'.
  • 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 an outlet header 24.
  • the heat exchanger 10 is preferably configured to operate in the turbulent regime, for example by introducing vortexes in the tube bank 20, or in the outlet header 24). This mode of operation improves heat exchange and mixes the condensate with liquid carryover from the separator 8 to catch any small droplets carried over.
  • the heat exchanger 10 may be configured to include one or more mixing elements within the tubes 20to promote turbulent flow.
  • each of the tubes 20 may include one or more twisted tape element(s).
  • the tubes 20 may thus be configured to operate as static mixers.
  • Figures 5 and 6 show two alternative types of heat exchanger 10, 10' comprising substantially horizontal heat exchange tubes 20.
  • Figure 5 shows a forced-draft type of heat exchanger 10
  • Figure 6 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 22 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 20is 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
  • the heat exchange tubes 20of the heat exchanger 10, 10' 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.
  • carbon steel is used for both the heat exchange tubes 20and the fins. Carbon steel has been found to be cost effective and least prone to mechanical failure.
  • 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 "inertia! 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.
  • 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.
  • demister 12 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%.
  • 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.
  • NCG gas is considered inert and is not accounted for. * No air recirculation at the fan outlet.
  • 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)
  • 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.
  • 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.
  • FIG. 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.
  • FIG. 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.
  • FIGS 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.
  • 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 refers to how far the end of one fin is from the fin on the adjacent tube 20. 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.
  • Figures 1 1 A and 11 B 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,
  • the fouling factor is based on the TEMA® standards for fouling.
  • 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.
  • 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
  • CFD computational fluid dynamics
  • 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 ail 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
  • 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.
  • 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 deduce, to some degree of certainty, that the average pressure loss would be 0.11 bara for a steady state operation.
  • 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.
  • the outlet header acted similarly to a centrifuge by forcing the condensed droplets to adhere to the wails 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.
  • the described system 2 cleans the steam by diluting the TDS concentration by ten-fold theoretically and then removing the diluted liquid.
  • the condensation rate of the steam can be controlled and 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.

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  • Engineering & Computer Science (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Sustainable Development (AREA)
  • Sustainable Energy (AREA)
  • Chemical & Material Sciences (AREA)
  • Combustion & Propulsion (AREA)
  • Physics & Mathematics (AREA)
  • Thermal Sciences (AREA)
  • Hydrology & Water Resources (AREA)
  • Heat-Exchange Devices With Radiators And Conduit Assemblies (AREA)

Abstract

Un système de traitement de vapeur pour une centrale d'énergie géothermique de tête de puits (2) comprend : un séparateur (8), pour recevoir un fluide diphasique d'un puits géothermique (4), et configuré de sorte à séparer la vapeur provenant du fluide diphasique; un échangeur de chaleur actif (10) configuré pour recevoir et condenser partiellement la vapeur provenant du séparateur; et un dévésiculeur (12) configuré pour éliminer un condensat de vapeur traitée. L'échangeur de chaleur (10) amène la vapeur à se condenser partiellement, formant ainsi un condensat. La formation de condensat est avantageuse en ce qu'elle dilue des constituants non souhaités transportés par un liquide dans la vapeur. Le condensat est ensuite éliminé par le dévésiculeur, entraînant avec lui la majeure partie des constituants non souhaités. Les constituants non souhaités peuvent comprendre de la silice, du fer et du chlorure, qui peuvent occasionner des dépôts de solides sur les pales d'une turbine (16).
PCT/GB2016/051580 2015-06-04 2016-05-31 Traitement de vapeur géothermique WO2016193700A1 (fr)

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US11905805B2 (en) 2020-11-13 2024-02-20 Baker Hughes Oilfield Low emissions well pad with integrated enhanced oil recovery

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JP2024513163A (ja) * 2021-04-06 2024-03-22 セジェージェー セルヴィシズ エスアーエス 水面下環境における地熱エネルギのスクリーニング、探索、および開発のためのシステムおよび方法

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