METHOD FOR REMOVING SCALE FROM GEOTHERMAL TURBINE BLADE AND METHOD FOR GEOTHERMAL POWER GENERATION

Abstract

A method for removing scale from a turbine blade in a geothermal power generation system has been developed. The developed method for removing scale from a turbine blade is characterized in that an alkaline solution and a chelating solution are injected into geothermal steam flowing into a turbine during power generation and geothermal scale formed adhering to the turbine blade is removed using the injected solutions. The present removal method can remove the scale adhering to a geothermal turbine blade in a short amount of time by improving the scale removal effect than heretofore. Further, a method for geothermal power generation preventing scale adhesion to the turbine blade is provided and a geothermal power generation system can be provided that enables continuous operation without performing opening and cleaning the turbine, even when geothermal steam containing 0.1 ppm or more of SiO.sub.2 and/or Cl is introduced into the turbine.

Claims

1-9. (canceled)

10. A method for removing geothermal scale from a turbine blade, the method comprising the steps of: injecting an alkaline solution and a chelating solution into geothermal steam flowing into a turbine during power generation; and removing geothermal scale formed adhering to a turbine blade using the solutions injected.

11. The method for removing scale from a turbine blade according to claim 10, wherein the alkaline solution is an aqueous solution containing sodium hydroxide and/or potassium hydroxide.

12. The method for removing geothermal scale from a turbine blade according to claim 10, wherein amounts of the solutions to be injected are determined on the basis of a turbine inlet steam pressure.

13. The method for removing geothermal scale from a turbine blade according to claim 11, wherein amounts of the solutions to be injected are determined on the basis of a turbine inlet steam pressure.

14. The method for removing geothermal scale from a turbine blade according to claim 10, wherein the solutions to be injected are injected into the geothermal steam after being diluted with condensate from a condenser, river water, or underground water.

15. The method for removing geothermal scale from a turbine blade according to claim 11, wherein the solutions to be injected are injected into the geothermal steam after being diluted with condensate from a condenser, river water, or underground water.

16. The method for removing geothermal scale from a turbine blade according to claim 10, wherein the solutions to be injected have a pH of 10 or higher.

17. The method for removing geothermal scale from a turbine blade according to claim 11, wherein the solutions to be injected have a pH of 10 or higher.

18. The method for removing geothermal scale from a turbine blade according to claim 14, wherein the solutions to be injected have a pH of 10 or higher.

19. The method for removing geothermal scale from a turbine blade according to claim 15, wherein the solutions to be injected have a pH of 10 or higher.

20. The method for removing geothermal scale from a turbine blade according to claim 10, wherein the chelate is aminocarboxylic acid-based chelate.

21. The method for removing geothermal scale from a turbine blade according to claim 11, wherein the chelate is aminocarboxylic acid-based chelate.

22. The method for removing geothermal scale from a turbine blade according to claim 14, wherein the chelate is aminocarboxylic acid-based chelate.

23. The method for removing geothermal scale from a turbine blade according to claim 15, wherein the chelate is aminocarboxylic acid-based chelate.

24. The method for removing geothermal scale from a turbine blade according to claim 16, wherein the chelate is aminocarboxylic acid-based chelate.

25. The method for removing geothermal scale from a turbine blade according to claim 17, wherein the chelate is aminocarboxylic acid-based chelate.

26. The method for removing geothermal scale from a turbine blade according to claim 18, wherein the chelate is aminocarboxylic acid-based chelate.

27. A method for geothermal power generation, comprising injecting an alkaline solution and a chelating solution into geothermal steam flowing into a turbine.

28. A geothermal power generation system, comprising: piping for delivering geothermal steam to a turbine; the turbine connected to the piping; and a power generator connected to the turbine, wherein the geothermal power generation system further includes a tank for storing an alkaline solution and a chelating solution, and the tank is connected to the piping so as to be able to inject the alkaline solution and the chelating solution into the geothermal steam.

29. The geothermal power generation system according to claim 28, wherein the geothermal steam flowing into the turbine contains SiO.sub.2 in an amount exceeding 0.1 ppm and/or Cl in an amount exceeding 0.1 ppm.

Description

BRIEF DESCRIPTION OF DRAWINGS

[0032] FIG. 1 is a configurational diagram of a geothermal power generation facility according to the present invention.

[0033] FIG. 2 is a chart showing an amount reduction rate (%) in Example 1.

[0034] FIG. 3 is a chart showing a dissolution rate (%) of each component in Example 1.

[0035] FIG. 4 is a chart showing a turbine control value in Example 2.

[0036] FIG. 5 is a configurational diagram of a conventional geothermal power generation facility.

DESCRIPTION OF EMBODIMENTS

(Embodiment 1)

[0037] Hereinafter, embodiments for carrying out the present invention will be described, but the embodiments of the present invention are not limited thereto and any modification can be made within the scope without departing from the gist of the present invention.

[0038] FIG. 5 shows a conventional configuration according to a geothermal power generation facility. Steam collected from the underground is delivered via a production well 1 to the ground to be supplied to a steam separator 3. The steam separator 3 separates hot water taken out together with the steam from the underground. The separated hot water is returned via a reinjection well 2 to the underground. Meanwhile, the separated steam is supplied via piping 41 to a turbine 5 and with the use of a rotational force of the turbine 5 rotated by the force of the steam, electricity is generated by a power generator 6. The generated electricity is transmitted via an electricity transmission line (not shown).

[0039] After passing through the turbine 5, the steam is cooled and condensed in a condenser 7 to become condensate. In this manner, since the pressure inside the condenser turns into a low-pressure state due to the condensation of the steam, a rotation efficiency of the turbine can be improved.

[0040] The condensate is supplied via piping 42 to a cooling tower 8 to be cooled, and is recirculated via piping 43 to the condenser 7 to be supplied for cooling the steam in the condenser 7. It should be noted that non-condensable gas contained in the geothermal steam is released from the condenser 7 to the atmosphere via piping 44.

[0041] Next, Embodiment 1 of the present invention will be described with reference to FIG. 1. In FIG. 1, except that a chemical solution tank 10, an injection amount adjuster 21, and piping 45, 46 are newly provided, Embodiment 1 is the same as the conventional example shown in FIG. 5.

[0042] The chemical solution tank 10 stores a mixed chemical solution (hereinafter referred to as mixed chemical solution) of an alkaline solution and a chelating solution for dissolving and removing scale. The alkaline solution may be any solution that dissolves silica scale, the examples of which include a sodium hydroxide solution, a potassium hydroxide solution, and the like. Further, the chelating solution may be any solution that dissolves calcium and metal such as iron, the examples of which include an aminocarboxylic acid-based chelating agent, a phosphonic acid-based chelating agent, and an organic acid chelating agent.

[0043] The mixed chemical solution in the chemical solution tank 10 is supplied via the piping 45 to condensate flowing through the piping 46. The supply amount of the mixed chemical solution is adjusted so that injection water to be injected into the turbine (hereinafter referred to as turbine injection water) has a desired pH value. The pH of the turbine injection water only needs to exhibit alkalinity, and when the pH is 10 or higher, a higher removal effect is exhibited, which is thus preferable, and when the pH is 11.5 or higher, a further higher removal effect is exhibited, which is thus particularly preferable.

[0044] The adjustment of the supply amount of the mixed chemical solution is performed by the injection amount adjuster 21 installed in a merging portion between the piping 45 and the piping 46. Further, the adjustment of the injection amount of the condensate is also performed by the injection amount adjuster 21.

[0045] Thereafter, the turbine injection water is merged with the steam from the underground flowing through the piping 41 and is supplied to the turbine 5.

[0046] It should be noted that as the other side to be supplied with the mixed chemical solution, river water, underground water, or the like can also be used in place of condensate, but in terms of avoiding corrosion of the steam piping, the turbine, or the like due to dissolved oxygen, the injection water preferably contains less dissolved oxygen. The condensate in the condenser 7 is in a vacuum deaeration state having less dissolved oxygen, and is thus preferable as the injection water.

[0047] The mixing ratio of the chelating solution in the mixed chemical solution is preferably 0.1 wt % to 1.0 wt %. The ratio of the chelating solution in the mixed chemical solution varies depending on the constituent minerals of the turbine scale, and thus can be optimized for each power generation plant. When the ratio of the chelating solution in the mixed chemical solution is lower than 0.1 wt %, the scale cannot be sufficiently removed. Meanwhile, when the ratio of the chelating solution is higher than 1.0 wt %, the scale removal effect cannot be improved so much for the amount of chelate used. Further, the mixing ratio of the alkaline solution in the mixed chemical solution is preferably 10 wt % to 25 wt %.

[0048] The injection amount of the turbine injection water is preferably 0.5 to 3 t/h relative to 100 t/h of the steam amount. This is because of the following reasons. When the injection amount accounts for less than 0.5% of the flow amount of the steam, the scale cannot be sufficiently removed and dissolution takes time. For reducing the dissolution time, a larger injection amount per unit time is favorable, while in a case where the injection amount accounts for over 3%, the erosion risk of the turbine increases.

[0049] The injection amount adjuster 21 has a function of adjusting separately the injection amounts of the mixed chemical solution and the injection water.

[0050] The embodiment may be made such that in place of the chemical solution tank 10 for storing the mixed chemical solution of the alkaline solution and the chelating solution, individual tanks for the alkaline solution and the chelating solution, as well as a control unit for the injection amount of the solution from each tank, are provided. With the chemical solution tanks separately provided for each chemical solution, there are advantages of enabling not only omission of a step of mixing the two chemical solutions, but also setting any mixing ratio of each chemical solution in accordance with the removal state of the scale. For example, adjustment is available such that upon commencement of scale removing work, initially, water or the alkaline solution is injected, and when the scale dissolution rate is lowered, mixing of the chelate is started or the like.

[0051] The mixed chemical solution is configured to be led to the turbine 5 through the piping 45, 46, 41. Further, a site where the mixed chemical solution merges from the piping 46 into the piping 41 may be anywhere between the steam separator 3 and the turbine 5, but is preferably a site near the turbine 5. This is because since drains are set between the merging site and the turbine 5 in some cases, when the merging site is far from the turbine 5, the mixed solution could leak from the drains. In other words, the merging site is preferably positioned between a drain on the upstream side of and closest to the turbine 5 and the turbine 5.

(Embodiment 2)

[0052] In the technical field of geothermal power generation, it is common practice that when scale adheres to the turbine, the scale is removed by opening and cleaning the turbine. For doing so, the turbine, that is, power generation is inevitably halted. Thus, to avoid such a circumstance, turbine manufacturers typically require a certain quality of the properties of the steam to be introduced into the turbine. This is a recommended value that does not cause any problems for long-term continuous operation, and troubles occurring from constant use of steam with properties that deviate from this are out of a compensation coverage by the turbine manufacturer.

[0053] For example, most turbine manufacturers recommend 0.1 ppm or less of both SiO.sub.2 and Cl in the steam flowing into the turbine, and it is empirically known that when the steam containing SiO.sub.2 and Cl exceeding this is used, adhesion of the turbine scale occurs.

[0054] On the other hand, when an apparatus described in Embodiment 1 is used to periodically inject the mixed chemical solution, the amount of scale adhesion can be constantly curbed to a certain amount or less, which does not cause trouble in power generation. Therefore, steam which could not be used for power generation in the past due to inferior steam properties, can also be used for power generation. In other words, steam that has conventionally been unavailable for power generation because of its poor steam properties also becomes available for power generation.

[0055] It should be noted that the injection of the mixed chemical solution may be performed not only on a regular basis, but also in such an irregular manner as injecting only when the scale adhesion amount reaches a certain amount, or on a continuous basis.

[0056] In particular, in the manner of injecting the mixed chemical solution only when the scale adhesion amount reaches a certain amount, damage to the turbine can be minimized, which is a further preferable embodiment.

[0057] It should be noted that whether the scale adhesion amount has reached a certain amount can be determined on the basis of whether a turbine control value, which will be described later, or a turbine inlet steam pressure has exceeded a predetermined value.

[0058] Further, the present embodiment is applicable not only to a case in which the steam properties are constantly inferior, but also to a case in which the quality of the steam properties cannot be stable in a nonconstant manner or a case in which at least one of SiO.sub.2 and Cl exceeds 0.1 ppm.

(Example 1)

[0059] The present invention was carried out using a scale sample collected from an actual geothermal turbine.

[0060] The solutions and the pH used are summarized in Table 1. For the mixed chemical solutions of the examples, a 0.1 wt % solution using EDTA was first prepared and then a small amount of a NaOH solution was added to adjust the pH of the solutions to be around 10, 11, and 12, respectively. As the alkaline solutions of comparative examples, a sodium hydroxide solution was used.

TABLE-US-00001 TABLE 1 Solution pH Example 1 NaOH + EDTA 10.07 Example 2 NaOH + EDTA 11.02 Example 3 NaOH + EDTA 12.07 Comparative Example 1 NaOH 9.92 Comparative Example 2 NaOH 11.01 Comparative Example 3 NaOH 11.97

[0061] A scale sample in an amount of 0.5 g collected from the actual geothermal turbine and pulverized was put in a Teflon (registered mark) container together with 20 mL of each solution shown in Table 1 and further, the Teflon container was entirely enclosed in a metal pressure container. Subsequently, reaction was conducted using a hydrothermal synthesis reactor unit (manufactured by Hiro Company, model KH-01) under the conditions of a reaction temperature at 130? C. and a 24-hour reaction time. In doing so, the reaction container was rotated six times per minute and the scale sample and the solution were continuously agitated.

[0062] After the hydrothermal synthetic reaction, residues were confirmed in all the samples. It should be noted that no distinct change in the form or the color tone of the scale samples was observed before and after the reaction. Based on the confirmed residue amount, the amount reduction rate (%) was calculated following an expression (Expression 1) below. The calculated results are shown in FIG. 2.

[00001]$\begin{array}{cc}\mathrm{amount}\mathrm{reduction}\mathrm{rate}\left(\%\right)=\frac{\left\{\begin{array}{c}\mathrm{scale}\mathrm{sample}\mathrm{weight}\mathrm{before}\mathrm{reaction}\left(g\right)-\\ \mathrm{scale}\mathrm{sample}\mathrm{residue}\mathrm{weight}\left(g\right)\end{array}\right\}}{\mathrm{scale}\mathrm{sample}\mathrm{weight}\mathrm{before}\mathrm{reaction}\left(g\right)}?100& \left[\mathrm{Expression}1\right]\end{array}$

[0063] It is clear from FIG. 2 that when the pH is the same, the mixed solution with the chelate mixed therein constantly exhibited a higher amount reduction rate. In particular, when the pH is 12, the difference was noticeable. This confirms that the effect of the mixed solution is particularly preferable when the pH is 11.5 or higher.

[0064] Next, for the samples after being subjected to the hydrothermal synthetic reaction, an analysis of concentration of components in each solution was conducted using an ICP Optical Emission Spectrometry (Shimadzu Corporation, model: ICPE-9000) and the dissolution rate of each component was obtained from the concentration following an expression (Expression 2) below. The obtained dissolution rate of each component is shown in FIG. 3.

[00002]$\begin{array}{cc}\mathrm{dissolution}\mathrm{rate}\mathrm{of}\mathrm{each}\mathrm{component}\left(\%\right)=\frac{\mathrm{dissolved}\mathrm{weight}\mathrm{of}\mathrm{each}\mathrm{component}\left(g\right)}{\mathrm{scale}\mathrm{sample}\mathrm{weight}\mathrm{before}\mathrm{reaction}\left(g\right)}?100& \left[\mathrm{Expression}2\right]\end{array}$

[0065] It is clear from FIG. 3 that in the case of the alkaline solution only, Ca, Fe, and Mg are scarcely dissolved. On the other hand, it is clear that when the mixed solution is used, the components are all dissolved to a certain amount. For example, the dissolution rate of Ca improves about ten times.

[0066] When a comparison is made between the examples and the comparative examples for SiO.sub.2 under the same pH condition, in all cases, the dissolution rate improved when the mixed solution was used as compared to the case in which only the alkaline solution was used. In particular, when the pH is 12, the dissolution rate was maximized and the difference in the dissolution rate widened. In view of these, it is assumed that the Ca, Fe, and Mg contained in the scale were dissolved so that the amorphous silica and the solution contacted more, and the dissolution rate of SiO.sub.2 was also increased.

[0067] It should be noted that as the other characteristics, the dissolution rate of the SiO.sub.2 exhibited a positive correlation with respect to the pH of the solution in both cases with the alkaline solution and with the mixed solution.

(Example 2)

[0068] Next, the present invention was carried out in an actual geothermal plant.

[0069] The turbine in the plant where the present invention was carried out generates power of 7 MW.

[0070] The present example used a mixed chemical solution in which 25 wt % NaOH as the alkaline solution and 0.1 wt % EDTA as the chelate were mixed. Further, the injection amount of the mixed chemical solution was adjusted so that the pH of the injection water after merged with condensate was from 11.0 to 12.0.

[0071] Further, in the present example, for the purpose of confirming the cleaning effect depending on the difference in the components of the injection water, in addition to the above, condensate (pH 4.5) alone and a cleaning solution with the pH adjusted to be 11.0 to 12.0 by mixing only the alkaline solution (NaOH) with condensate were also used as the injection water.

[0072] Then, as a first stage, only the condensate was injected at a rate of 1.2 t/h for about one hour from the start of a cleaning test, and subsequently, as a second stage, the injection water using the alkaline solution was injected for 2.5 hours (the injection amount at 1.2 t/h), and then finally, as a third stage, the injection water using the mixed chemical solution was injected for 19 hours (the injection amount at 1.2 t/h).

[0073] Further, as an indicator for confirming the cleaning effect, a turbine control value was used. The turbine control value herein is a value determined by an expression (Expression 3) below, and a greater value is exhibited for greater precipitation of the scale in the turbine blade.

[00003]$\begin{array}{cc}\mathrm{turbine}\mathrm{control}\mathrm{value}=\frac{\mathrm{turbine}\mathrm{inlet}\mathrm{pressure}\left(\mathrm{barA}\right)}{\begin{array}{c}\mathrm{flow}\mathrm{rate}\mathrm{of}\mathrm{steam}\\ \mathrm{introduced}\mathrm{into}\mathrm{turbine}\left(\mathrm{kg}/h\right)\end{array}}& \left[\mathrm{Expression}3\right]\end{array}$

[0074] The results are shown in FIG. 4. It should be noted that in FIG. 4, the unit in the lateral axis represents time (starting time of injecting injection water set at 0:00) and the longitudinal axis represents the turbine control value. In every stage, in 10 to 20 minutes after switching the cleaning solution, the cleaning effect appeared. Further, in the case of condensate only, the scale removal effect subsided to some extent when one hour passed after the injection, but when the alkaline solution was injected afterwards as the second stage, the removal effect was further exhibited, and after 2.5 hours passed, the removal effect gradually weakened. As the third stage, when the mixed chemical solution was injected, the scale removal effect was remarkably reexhibited. In every stage, whether to stop the cleaning can be determined when the reduction rate of the turbine control value becomes constant. Similarly, in normal operation (when power generation is performed without injecting water), the timing of performing turbine cleaning can be determined on the basis of the increase in the turbine control value.

[0075] It should be noted that the decrease in the turbine control value in each stage was 29.4% in the first stage (injection water only), 48.1% in the second stage (alkaline solution only), and 22.5% in the third stage (mixed chemical solution).

[0076] It is clear from Example 2 that the scale cleaning effect is the highest with the mixed chemical solution, followed by the alkaline solution and then the condensate. It should be noted that as an indicator for determining the cleaning effect, the value of the turbine inlet steam pressure can also be used in place of the turbine control value.

INDUSTRIAL APPLICABILITY

[0077] According to the present invention, since the removal of the scale from the turbine blade can be practically performed while generating power in the geothermal power generation, the power generation can be stably continued without reducing the power output due to the scale. Further, the present invention enables continuous power generation without performing cleaning with the turbine blade opened or the like even when geothermal steam containing 0.1 ppm or more of SiO.sub.2 and/or Cl as the steam properties is used.

[0078] Further, the present technique is applicable not only to the geothermal power generation, but also to the thermal power generation (including the hot spring power generation) using steam with a silica component, a calcium component, and the like dissolved therein in a similar manner.

REFERENCE SIGNS LIST

[0079] 1 production well [0080] 2 reinjection well [0081] 3 steam separator [0082] 41-46 piping [0083] 5 turbine [0084] 6 power generator [0085] 7 condenser [0086] 8 cooling tower [0087] 10 chemical solution tank [0088] 21 injection amount adjuster