Heat collection method

Abstract

To provide a heat collection method which provides high heat collection efficiency from a high-temperature rock body.SOLUTION: A heat collection method collects heat from a high-temperature rock body G by collecting a heat medium W injected into an injection well H and discharged from a production well J via the high-temperature rock body G. The heat collection method includes: a well establishment process S101 of establishing a plurality of wells A reaching the high-temperature rock body G; a first test process S103 of repeatedly executing measurement of a measurement value showing a state of the heat medium W discharged from a production well candidate j when the heat medium W is injected into an injection well candidate h with a part of the well A as the injection well candidate h and others as the production well candidate j, by changing a combination of the injection well candidate h and the production well candidate j; and a well deciding process S105 for deciding the injection well H and the production well J to be used for the heat collection from the plurality of wells A based on a test result obtained in the first test process S103.SELECTED DRAWING: Figure 2

Description

[Technical Field]

[0001] The present invention relates to a method for recovering heat from a hot dry rock mass. [Background technology]

[0002] A known conventional heat recovery method in this field is described in Patent Document 1 below. In this method, injection and production wells are drilled to reach a hot dry rock mass underground, and a liquid heat transfer medium (e.g., water) is pumped from the injection well to the hot dry rock mass. This heat transfer medium is heated by the hot dry rock mass as it travels through the hot dry rock mass to the production well, and is then recovered from the production well as a high-temperature liquid and gas. This heat transfer medium is sent to a power plant to generate electricity, and is then pumped again from the injection well to the hot dry rock mass. In this way, the heat from the underground hot dry rock mass can be recovered to the surface and used as electrical energy. [Prior art documents] [Patent documents]

[0003] [Patent Document 1] Japanese Patent Application Publication No. 61-79942 [Patent Document 2] Patent No. 6565342 Summary of the Invention [Problem to be solved by the invention]

[0004] However, the heat recovery efficiency of this method depends on the permeability of the heat transfer medium through the hot dry rock mass, and even if some preliminary investigations of the hot dry rock mass have been conducted, it is not always possible to achieve highly efficient heat recovery. For example, it is possible that the heat transfer medium injected through the injection well is not recovered at all from the production well. Therefore, an object of the present invention is to provide a heat recovery method that can achieve highly efficient heat recovery from hot dry rock mass. [Means for solving the problem]

[0005] The gist of the present invention lies in the following [1] to [7].

[0006] [1] A heat recovery method for recovering heat from a hot rock mass by recovering a heat transfer medium that is injected into an injection well, passes through a hot rock mass, and is discharged from a production well, the heat recovery method comprising: a well construction step for constructing a plurality of wells that reach the hot rock mass; a first testing step for repeatedly measuring values ​​indicating the state of the heat transfer medium discharged from the candidate production wells when the heat transfer medium is injected into the candidate injection wells, while changing the combination of the candidate injection wells and the candidate production wells; and a well determination step for determining the injection wells and production wells to be used for heat recovery from among the plurality of wells based on the test results obtained in the first testing step.

[0007] [2] The heat recovery method according to [1], further comprising a crack generation step of artificially generating cracks in the hot dry rock.

[0008] [3] The heat recovery method according to [1] or [2], further comprising: an optical fiber sensor installation step of installing an optical fiber sensor in the well that functions as a strain sensor for the well; a crack detection step of detecting the positions of multiple cracks present in the candidate injection well based on the strain in the candidate injection well detected by the optical fiber sensor; a second test step of installing a pair of test packers in the injection well determined in the well determination step at positions that vertically sandwich some of the multiple cracks detected in the crack detection step to form an injection test area sandwiched between the test packers, and repeatedly measuring, while changing the injection test area, values ​​that indicate the state of the heat medium discharged from the production well when the heat medium is injected into the injection test area; and an injection area determination step of determining an injection area to be used for heat recovery from among the multiple injection test areas in the injection well based on the test results obtained in the second test step.

[0009] [4] The heat recovery method according to [3], further comprising a packer permanent installation step of installing a pair of permanent packers to permanently form the injection area determined in the injection area determination step.

[0010] [5] The heat recovery method according to [3] or [4], further comprising a crack closing step of closing the cracks present in areas other than the injection area determined in the injection area determination step.

[0011] [6] The heat recovery method according to [5], wherein in the crack sealing step, a water-stopping material is injected into the cracks present in areas other than the injection area.

[0012] [7] The heat recovery method according to [5], wherein in the crack plugging step, supercritical carbon dioxide is injected into the cracks present in an area other than the injection area. [Effects of the Invention]

[0013] According to the present invention, it is possible to provide a heat recovery method that can obtain high heat recovery efficiency from a hot dry rock mass. [Brief explanation of the drawings]

[0014] [Figure 1] 1 is a diagram showing a heat recovery system applied to a heat recovery method of a first embodiment. [Figure 2] FIG. 2 is a flow diagram of a heat recovery method according to the first embodiment. [Figure 3] FIG. 1(a) is a diagram showing a well construction step in the heat recovery method, and FIG. 1(b) is a diagram showing a first test step in the heat recovery method. [Figure 4] FIG. 2 is a block diagram showing a heat recovery section of the heat recovery system. [Figure 5] FIG. 6 is a flow diagram of a heat recovery method according to a second embodiment. [Figure 6] FIG. 10 is a flow diagram of a heat recovery method according to a third embodiment. [Figure 7] FIG. 10(a) is a plan view of a well illustrating the step of installing an optical fiber sensor in the third embodiment, and FIG. [Figure 8] 8(a) is a plan view of a well showing the step of installing an optical fiber sensor in the third embodiment, continuing from FIG. 7, and FIG. 8(b) is a cross-sectional view thereof. [Figure 9] 8(a) is a plan view of a well showing the step of installing an optical fiber sensor in the third embodiment, continuing from FIG. 7, and FIG. 8(b) is a cross-sectional view thereof. [Figure 10] (a) is a cross-sectional view of a well showing the crack detection process in the third embodiment, (b) is a cross-sectional view of a well showing the second testing process in the third embodiment, and (c) is a cross-sectional view of a well showing the packer installation process in the third embodiment. [Figure 11] FIG. 10 is a flow diagram of a heat recovery method according to a fourth embodiment. [Figure 12] FIG. 10(a) is a cross-sectional view of a well illustrating a crack plugging step in the fourth embodiment, and FIG. 10(b) is a cross-sectional view of a well illustrating a modified example of the crack plugging step. DETAILED DESCRIPTION OF THE INVENTION

[0015] [First embodiment] A first embodiment of a heat recovery method according to the present invention will be described in detail below with reference to the drawings. Fig. 1 is a cross-sectional view schematically showing a heat recovery system applied to the heat recovery method of the embodiment. As shown in Fig. 1, the heat recovery method of this embodiment recovers heat from a hot dry rock mass G by injecting a heat transfer medium W through an injection well H, passing the heat transfer medium W through an underground hot dry rock mass G, and recovering the heat transfer medium W discharged from a production well J.

[0016] The heat recovery system 3 constructed here comprises an injection well H, a production well J, and a heat recovery section 5. The injection well H and the production well J are drilled from the surface to reach the underground hot dry rock G. The injection well H and the production well J are bare holes at least in the portion within the hot dry rock G, and in this portion the rock surface of the hot dry rock G is exposed on the inner wall surface of the injection well H and the production well J. The depth of the injection well H and the production well J is, for example, about 1000 m. As the depth increases, the inner diameters of the injection well H and the production well J become gradually smaller, and in the portion within the hot dry rock G, the inner diameters of the injection well H and the production well J are, for example, about 150 mm. Note that the state in which the inner diameters of the injection well H and the production well J differ in stages is not illustrated.

[0017] Furthermore, the injection well H and the production well J penetrate numerous fractures 11 present in the hot dry rock mass G. The presence of these fractures 11 makes the hot dry rock mass G permeable to allow the heat transfer medium W to pass through. Some of the main fractures 11 are penetrated by multiple wells among the injection wells H and the production wells J, and the heat transfer medium W can move between the wells through the fractures 11. The heat recovery system 3 may have multiple injection wells H and multiple production wells J. In the example of FIG. 1, the heat recovery system 3 has one injection well H and four production wells J.

[0018] The heat recovery section 5 is connected to the injection well H and the production well J, and a circulation path for the heat transfer medium W is formed in the order of the injection well H, the hot dry rock mass G, the production well J, and the heat recovery section 5. Valves V are appropriately installed at the surface entrances of the injection well H and the production well J for the purpose of adjusting the flow rate of the heat transfer medium W, etc.

[0019] The heat recovery section 5 includes, for example, a pump that pressure-feeds the heat medium W to the entrance of the injection well H, a heat exchanger that recovers heat from the heat medium W received from the production well J, and a power generation device that generates electricity using the heat recovered by the heat exchanger. The heat recovered from the hot dry rock G is converted into electrical energy by the heat recovery section 5 and effectively utilized. Note that a power generation turbine may be used instead of the heat exchanger and power generation device, and power may be generated directly from the high-temperature heat medium W by the power generation turbine. As the heat medium W, for example, water, carbon dioxide, etc. may be used.

[0020] In this heat recovery system 3, a liquid heat transfer medium W is injected into an injection well H by the pressure of a pump in the heat recovery section 5. This heat transfer medium W enters a fracture 11 in a hot dry rock mass G from the injection well H, moves through the fracture 11 within the hot dry rock mass G, and reaches a production well J. The heat transfer medium W that reaches the production well J has absorbed the heat of the hot dry rock mass G and has become hot, and is ejected from the production well J as a mixture of high-temperature gas and high-temperature liquid, for example. When water is used as the heat transfer medium W, for example, hot water and steam are ejected from the production well J. The heat transfer medium W ejected from the production well J is introduced into the heat recovery section 5. In the heat recovery section 5, the heat of the heat transfer medium W is recovered, and the cooled heat transfer medium W is pumped back to the injection well H by the pump.

[0021] 2, the heat recovery method of this embodiment includes a heat recovery system construction step S100 for constructing the above-mentioned heat recovery system 3, and a heat recovery operation step S200 for recovering heat by operating this heat recovery system 3. Of these steps, the heat recovery system construction step S100 includes a well construction step S101, a first test step S103, a well determination step S105, and a piping step S131, which will be described below.

[0022] (Well construction process S101) As shown in FIG. 3(a), a hot dry rock mass G exists underground in the area where the heat recovery method of this embodiment is implemented. In the well construction step S101, multiple wells A are constructed from the surface to reach the hot dry rock mass G. Each well A will ultimately be used as an injection well H or a production well J (FIG. 1) of the heat recovery system 3. Here, an example will be described in which five wells A are constructed as illustrated in FIG. 3(a). When distinguishing between the five wells A, they will be referred to as "well A1," "well A2," "well A3," "well A4," and "well A5," respectively. Note that in each figure, wells A1 to A5 are schematically shown lined up in a straight line for convenience of illustration, but in reality, wells A1 to A5 do not necessarily exist in a straight line and are constructed in appropriate planar positions based on prior surveys, etc.

[0023] The well A constructed here has the same configuration as the injection well H and production well J described above. That is, the well A is an open hole at least in the part inside the hot dry rock mass G, and in this part the rock surface of the hot dry rock mass G is exposed on the inner wall of the well A. The depth of the well A is, for example, about 1000 m. As the depth increases, the inner diameter of the well A gradually decreases, and in the part inside the hot dry rock mass G the inner diameter of the well A is, for example, about 150 mm. Such a well A is constructed using a known boring method and penetrates the numerous fractures 11 that exist in the hot dry rock mass G.

[0024] (First test process S103) Next, in the first test step S103, a test is performed to determine what combination of injection well H and production well J should be selected from wells A1 to A5 to achieve good heat recovery efficiency. As a specific method, one of wells A1 to A5 is set as a candidate for injection well H (candidate injection well h), and the other four are set as candidates for production well J (candidate production well j). Then, as shown in FIG. 3(b), a test pump 13 for injecting heat transfer medium W is connected to candidate injection well h, and a heat measurement unit 15 is connected to candidate production well j. Note that FIG. 3(b) illustrates a case where well A1 is set as candidate injection well h, and the other wells A2 to A5 are set as candidate production well j.

[0025] The heat measurement unit 15 measures the amount and temperature of the heat transfer medium W ejected from each candidate production well j. Specifically, as shown in FIG. 4, the heat measurement unit 15 has a gas-liquid separator 17 that separates the heat transfer medium W ejected from the candidate production well j into gas and liquid. The heat measurement unit 15 also has a gas-phase flowmeter 19a that measures the flow rate of the gas phase of the heat transfer medium W separated by the gas-liquid separator 17, and a gas-phase thermometer 19b that measures the temperature of the gas phase. The heat measurement unit 15 also has a liquid-phase flowmeter 21a that measures the flow rate of the liquid phase of the heat transfer medium W separated by the gas-liquid separator 17, and a liquid-phase thermometer 21b that measures the temperature of the liquid phase. As the gas-liquid separator 17, for example, a known gas-liquid separator such as a vane separator or a centrifugal separator is used. As the gas-phase flowmeter 19a, a known steam flowmeter such as a differential pressure steam flowmeter, an ultrasonic steam flowmeter, or a vortex steam flowmeter is used. As the liquid-phase flowmeter 21a, for example, a triangular weir is used. As the gas-phase thermometer 19b and the liquid-phase thermometer 21b, known thermometers are appropriately used.

[0026] In the first test step S103, the combination of candidate injection well h and candidate production well j is changed among wells A1 to A5, and measurements by the thermal measurement unit 15 as described above are repeated. For example, in the first test step S103 in this embodiment, measurements are taken for five combinations, such as a combination in which well A1 is the candidate injection well h and the others are the candidate production well j, a combination in which well A2 is the candidate injection well h and the others are the candidate production well j, and a combination in which well A5 is the candidate injection well h and the others are the candidate production well j.

[0027] (Well determination step S105) In the well determination step S105, based on the test results obtained in the first test step S103, i.e., based on the measurement values ​​obtained from each heat measurement unit 15 in the first test step S103, it is determined what combination of injection wells H and production wells J should be selected from wells A1 to A5 to achieve good heat recovery efficiency. Then, the combination determined to have the best heat recovery efficiency is determined as the combination of injection wells H and production wells J to be adopted in the heat recovery system 3. In other words, here, the injection wells H and production wells J to be used in the heat recovery system 3 are determined from wells A1 to A5.

[0028] The definition of "high heat recovery efficiency" is explained below. For example, when a predetermined temperature and amount of heat transfer medium W is injected into candidate injection well h, the evaluation index for the heat recovery efficiency is the total enthalpy value of the heat transfer medium W injected from all candidate production wells j. In other words, the larger the enthalpy, the better the heat recovery efficiency is evaluated. The enthalpy of the heat transfer medium W injected from one candidate production well j can be derived using a known method based on the gas phase flow rate measurement value (FG), gas phase temperature measurement value (TG), liquid phase flow rate measurement value (FL), and liquid phase temperature measurement value (TL) obtained by the heat measurement unit 15. Therefore, the total enthalpy of the heat transfer medium W injected from all candidate production wells j can be calculated.

[0029] (Piping process S131) In the piping step S131, the injection well H and production well J determined as described above are connected to the above-ground heat recovery unit 5 by predetermined piping. That is, as shown in FIG. 1, the ground port of the injection well H is connected to the outlet of the heat transfer medium W in the heat recovery unit 5, and the ground ports of each production well J are connected in parallel to the inlets of the heat transfer medium W in the heat recovery unit 5. Note that FIG. 1 illustrates a case where well A1 is determined as the injection well H, and wells A2 to A5 are determined as the production wells J. In this way, a heat recovery system 3 that recovers heat from hot dry rock G is constructed.

[0030] In the heat recovery operation process S200, the heat recovery system 3 completed in the heat recovery system construction process S100 is operated, and as mentioned above, the heat from the hot dry rock mass G is recovered in the heat recovery section 5 on the ground and ultimately converted into electrical energy for effective use.

[0031] The effects of the heat recovery method of this embodiment will be described. According to this heat recovery method, the first test step S103 and the well determination step S105 are performed in the heat recovery system construction step S100, and a combination of the injection well H and the production well J with high heat recovery efficiency is selected. Therefore, in the heat recovery operation step S200, a situation in which the heat medium W injected from the injection well H cannot be recovered at all from the production well J is avoided, and highly efficient heat recovery is achieved by the heat recovery system 3.

[0032] Another method for reliably recovering the heat transfer medium injected underground is to install a closed loop between the surface and the hot dry rock mass, including piping that runs through the hot dry rock mass (see Patent Document 2, etc.). However, drilling the hot dry rock mass horizontally to run the piping is difficult, and in order to achieve high heat recovery efficiency, it is necessary to grasp the hot dry rock mass in detail and ensure that the piping runs through it. Another problem is that the piping in the hot dry rock column is prone to high-temperature corrosion. In contrast, the heat recovery method of this embodiment makes installation less difficult and reduces concerns about high-temperature corrosion of the piping.

[0033] Second Embodiment Next, a second embodiment of the heat recovery method of the present invention will be described. Below, the heat recovery method of this embodiment will be described mainly in terms of the differences from the first embodiment. Steps and components that are the same as or equivalent to those of the first embodiment will be assigned the same reference numerals, and duplicated explanations will be omitted. In addition to the first embodiment, the heat recovery method of this embodiment includes a crack generation step 104, as shown in the flow diagram of FIG. 5. In other respects, it is the same as the first embodiment.

[0034] In the first test process S103 (see Figure 3(b) etc.), if the amount of heat transfer medium W ejected from the candidate production well j is insufficient compared to the amount of heat transfer medium W injected from the candidate injection well h, there is a risk that the heat ultimately recovered from the hot dry rock mass G by the heat recovery system 3 will not be sufficient. Therefore, in this case (if the decision S103a in Figure 5 is NO), the crack generation process S104 described below is executed.

[0035] (Crack generation process S104) In the fracture generation step S104, fractures 11 are artificially generated in the hot dry rock G by hydraulic fracturing. Specifically, fractures 11 are generated in the hot dry rock G by injecting ultra-high-pressure water into the hot dry rock G through well A constructed in the well construction step S101 (see FIG. 3(a) and other figures). Alternatively, instead of hydraulic fracturing, blasting may be performed in well A to generate fractures 11 in the hot dry rock G by explosive pressure. These processes generate new fractures 11 in the hot dry rock G in addition to the original fractures 11. The original fractures 11 also widen. Therefore, the movement of the heat transfer medium W between wells A1 to A5 through the fractures 11 increases, i.e., the permeability of the heat transfer medium W in the hot dry rock G improves. As a result, the amount of heat transfer medium W ejected from the candidate production well j in the first test step S103 is also expected to increase.

[0036] 5, after the above-mentioned crack generation step S104, the first test step S103 is executed again, and a determination S103a of the amount of heat transfer medium W ejected from the candidate production well j is executed. In this determination S103a, if it is determined that the amount of ejection is sufficient (YES in S103a), the well determination step 105 is executed. Note that the amount of heat transfer medium W ejected in the determination S103a is acquired based on the measurement values ​​obtained by the gas-phase flow meter 19a and the liquid-phase flow meter 21a of the heat measurement unit 15.

[0037] According to the heat recovery method of this embodiment, the crack generation process S104 is executed, which improves the permeability of the heat medium W in the high-temperature dry rock G, and ultimately increases the movement of the heat medium W through the crack 11 between the injection well H and the production well J, thereby increasing the amount of heat that can be recovered from the high-temperature dry rock G by the heat recovery system 3.

[0038] In the above example, the crack generation process S104 is executed depending on the result of the judgment S103a of the ejection amount after the first test process S103, but this is not limited to this, and the first crack generation process S104 may be executed before the first first test process S103.

[0039] Third Embodiment Next, a third embodiment of the heat recovery method of the present invention will be described. Below, the heat recovery method of this embodiment will be mainly described with respect to the differences from the first embodiment. The same or equivalent steps and components as those of the first embodiment will be assigned the same reference numerals, and redundant explanations will be omitted.

[0040] In the heat recovery method of this embodiment, not only is the optimal combination of the injection well H and the production well J determined based on the first test step S103, but also the optimal injection region into which the heat transfer medium W should be injected within the injection well H is determined based on the second test step S111 described below. In other words, it is determined at what depth in the injection well H the heat transfer medium W should be concentratedly injected.

[0041] Specifically, as shown in the flow chart of Figure 6, the heat recovery method of this embodiment further includes an optical fiber sensor installation process S102, a crack detection process S109, a second testing process S111, an injection area determination process S113, and a packer installation process S115 in addition to the first embodiment.

[0042] (Optical fiber sensor installation process S102) The optical fiber sensor installation step S102 is performed before the first testing step S103. In the optical fiber sensor installation step S102, optical fiber sensors are installed on the inner wall surfaces of all wells A (wells A1 to A5) constructed in the well construction step S101. These optical fiber sensors extend throughout the entire depth direction of well A and function as strain sensors that detect strain in the depth direction of well A. Since the optical fiber sensors will be exposed to high temperatures, for example, 200 to 300°C, within well A, optical fiber sensors with the required heat resistance are selected here.

[0043] 7 to 9 are cross-sectional views sequentially illustrating a method for installing an optical fiber sensor 21 on the inner wall surface of a well A. In each figure, (a) shows a plan view of well A, and (b) shows a cross-sectional view of well A. First, as shown in FIG. 7, a steel formwork material 23 extending throughout the entire depth direction of well A is inserted into well A from the surface entrance. The formwork material 23 has a U-shaped cross section, and a sensor accommodating space 25 is formed within well A, surrounded by the inner wall surface of well A and the formwork material 23. The dimension of the sensor accommodating space 25 in the radial direction of well A is, for example, approximately 50 mm. Furthermore, the optical fiber sensor 21 is inserted throughout the entire depth direction into this sensor accommodating space 25, and a mortar injection pipe 27 is also inserted. Meanwhile, a packer 31 is inserted into a space 29 outside the sensor accommodating space 25 within well A from the surface entrance. A plurality of packers 31 are arranged in the depth direction at predetermined intervals, and each packer 31 is connected to an air pipe 33 for feeding air to inflate the packer 31.

[0044] Next, as shown in FIG. 8, air is sent into each packer 31 from the ground entrance through the air supply pipe 33, causing each packer 31 to expand, pressing the formwork material 23 against the inner wall surface of well A. Then, mortar 35 is injected into the sensor housing space 25 from the ground entrance through the mortar injection pipe 27. At this time, the action of the packers 31 suppresses the hydraulic head pressure of the mortar 35, and the mortar 35 fills the sensor housing space 25. Thereafter, as shown in FIG. 9, the mortar injection pipe 27 is removed, and after the mortar 35 hardens, the air is released from the packers 31 and the packers 31 are removed. This leaves the optical fiber sensors 21 embedded in the hardened mortar 35 and protected by the formwork material 23 on the inner wall surface of well A. In this way, the optical fiber sensors 21 integrated into the inner wall surface are installed throughout the entire depth direction on the inner wall surface of well A.

[0045] In the above example, multiple packers 31 are arranged at intervals in the depth direction, but instead, for example, a single packer extending over the entire depth direction may be used. Also, instead of pumping air into the packers 31 to expand them, water may be pumped into them to expand them.

[0046] Since the optical fiber sensor 21 deforms in the depth direction, following the inner wall surface of the well A, the deformation distribution in the depth direction of the well A can be detected by detecting the strain distribution in the depth direction of the optical fiber sensor 21. Specifically, the end of the optical fiber sensor 21, which is pulled out from the surface entrance of the well A, is connected to a strain measurement device 39 (see FIG. 10(a)), such as an OTDR (Optical Time Domain Reflectometer) or a BOTDR (Brillouin Optical Time Domain Reflectometer). When pulsed light is incident on the optical fiber sensor 21 from the strain measurement device 39, scattered light from each portion of the optical fiber sensor 21 in the longitudinal direction returns to the strain measurement device 39. By analyzing this scattered light by the strain measurement device 39, the strain at each portion of the optical fiber sensor 21 in the longitudinal direction can be determined, for example, at intervals of about 50 mm. In other words, the strain at each portion of the well A in the depth direction can be detected.

[0047] (Crack detection process S109) The crack detection step S109 is performed in parallel with the first test step S103. In the crack detection step S109, as shown in FIG. 10(a), a measurement device 39 is connected to the end of an optical fiber sensor 21 drawn from the surface entrance of the candidate injection well h, and the depthwise strain of the candidate injection well h is measured. In the first test step S103, pressure is applied to the candidate injection well h by injecting the heat medium W, causing each fracture 11 present in the candidate injection well h to expand in the depthwise direction. Then, in the crack detection step S109, the expansion of each fracture 11 is detected by the optical fiber sensor 21, so that the depthwise position of each fracture 11 present in the candidate injection well h can be detected.

[0048] (Second test process S111) The second test process S111 (FIG. 6) is performed after the first test process S103, the fracture detection process S109, and the well determination process S105, and is performed for the injection well H determined in the well determination process S105. The second test process S111 differs from the first test process S103 in the method of injecting the heat transfer medium W into the injection well H.

[0049] The injection well H determined in the well determination step S105 has a plurality of fractures 11 detected in the fracture detection step S109. In the first test step S103, the heat transfer medium W is injected into the entire candidate injection well h, and the heat transfer medium W penetrates into the plurality of fractures 11 in the candidate injection well h, whereas in the second test step S111, the heat transfer medium W is injected concentratedly into specific fractures 11 among the plurality of fractures 11 in the injection well H. A method for realizing such injection of the heat transfer medium W will be described below.

[0050] Here, as shown in Figure 10, it is assumed that the injection well H involved in the test has three fractures 11 that have been detected in the fracture detection step S109. When distinguishing between the fractures 11, they are referred to as fractures 11a, 11b, and 11c, respectively. Furthermore, within the injection well H, an area that includes the fractures 11 and has a vertical width of approximately 500 mm is referred to as the injection test area 45. When distinguishing between the injection test areas 45, they are referred to as injection test areas 45a, 45b, and 45c, corresponding to the fractures 11a, 11b, and 11c, respectively.

[0051] In the second test step S111, as shown in FIG. 10(b), an inner pipe 41 is inserted from the ground entrance of the injection well H, and a pair of upper and lower water-stopping test packers 43, 43 are attached to the lower end of the inner pipe 41. First, the lower end of the inner pipe 41 is moved near the crack 11a, and the test packers 43, 43 are positioned so as to sandwich the crack 11a from above and below. Then, air is sent from the ground through an air pipe (not shown) into the test packers 43, 43. As a result, the test packers 43, 43 expand and are fixed to the inner wall surface of the injection well H, forming a watertight injection test area 45a as the area sandwiched between the test packers 43, 43. As described above, the vertical width of the injection test area 45a is, for example, approximately 500 mm, and the crack 11a exists in this injection test area 45a.

[0052] At the ground entrance, a test pump 13 is connected to the inner pipe 41, and a heat measurement unit 15 (see Figure 3(b)) is connected to each production well J. Then, the heat transfer medium W is injected from the test pump 13 through the inner pipe 41 into the injection test area 45a. Then, the heat transfer medium W enters the fracture 11a from the injection test area 45a, moves through the fracture 11a within the hot dry rock G, and reaches each production well J. At this time, the heat transfer medium W from the test pump 13 passes through the fracture 11a but does not pass through the other fractures 11b and 11c. Meanwhile, the heat measurement unit 15 connected to each production well J measures the amount and temperature of the heat transfer medium W ejected from each production well J in the same manner as in the first test step S103.

[0053] Then, in the second test process S111, the inner pipe 41 and the test packers 43, 43 are attached and detached to positions corresponding to the cracks 11a to 11c in the injection well H, i.e., while changing the injection test areas 45a to 45c, measurements by the thermal measurement unit 15 as described above are repeated.

[0054] (Injection area determination step S113) In the injection region determination step S113, based on the test results obtained in the second test step S111, i.e., based on each measurement value obtained from the thermal measurement unit 15 in the second test step S111, it is determined which injection test region 45 of the injection well H should be injected with the heat transfer medium W to achieve good heat recovery efficiency. In this case, the same evaluation index as the evaluation index for heat recovery efficiency in the well determination step S105 described above may be used to evaluate the heat recovery efficiency. Then, the injection test region 45 determined to have the best heat recovery efficiency is determined as the injection region 46 to be adopted in the heat recovery system 3. For example, more than one of the injection test regions 45a to 45c may be determined as the injection region 46.

[0055] (Packer installation process S115) In the packer permanent installation step S115, water-stopping packers are permanently installed to permanently form the injection region 46 determined in the injection region determination step S113. That is, as shown in FIG. 10(c), an inner pipe 51 is inserted from the ground entrance of the injection well H, and a pair of upper and lower permanent water-stopping packers 53 are attached to the lower end of the inner pipe 51. The inner pipe 51 and the permanent packers 53 are moved to the position of the injection region 46, and air is sent into the permanent packers 53 from the ground through an air pipe (not shown), thereby permanently fixing the permanent packers 53 to the inner wall surface of the injection well H. This permanently forms a watertight injection region 46 as the region sandwiched between the permanent packers 53. The cracks 11 present in this injection region 46 are the most suitable cracks for allowing the heat transfer medium W from the injection well H to enter the hot dry rock mass G. FIG. 10(c) illustrates a case where the injection test region 45a is determined as the injection region 46.

[0056] (Piping process S131) Thereafter, in the piping step S131, the inner pipe 51 installed in the injection well H as described above is connected to the outlet of the heat transfer medium W in the heat recovery section 5 by a predetermined piping, and the surface port of each production well J is connected to the inlet of the heat transfer medium W in the heat recovery section 5. In this case, the heat transfer medium W pumped from the heat recovery section 5 is injected into the injection region 46 of the injection well H through the inner pipe 51 and penetrates into the fractures 11 present in the injection region 46. Then, this heat transfer medium W travels through the fractures 11 within the hot dry rock mass G to reach each production well J, and then sprays out from each production well J and is introduced into the heat recovery section 5. In other words, the heat transfer medium W is selectively injected only into the fractures 11 within the injection region 46 of the injection well H, and is not injected into other fractures 11 within the injection well H.

[0057] According to the heat recovery method of this embodiment, the heat transfer medium W is selectively injected only into the cracks 11 that can achieve high heat recovery efficiency among the cracks 11 present in the injection well H of the heat recovery system 3. Therefore, in addition to the first embodiment, even more efficient heat recovery is achieved. Also, by avoiding the injection of the heat transfer medium W into the cracks 11 with low heat recovery efficiency, waste of the heat transfer medium W is reduced.

[0058] [Fourth embodiment] Next, a fourth embodiment of the heat recovery method of the present invention will be described. In the heat recovery method of this embodiment, as shown in Fig. 11, the following crack plugging step S117 is performed instead of the packer installation step S115 of the third embodiment. In the crack plugging step S117, cracks 11 that exist in areas of the injection well H other than the injection area 46 are plugged. In the following description, the cracks 11 to be plugged will be referred to as cracks 11s.

[0059] (Crack Closure Process S117) In the crack plugging step S117, as shown in FIG. 12(a), an inner pipe 61 is inserted from the ground entrance of the injection well H, and a pair of upper and lower packers 63, 63 are attached to the lower end of the inner pipe 61. The packers 63, 63 are moved to the position of the crack 11s, and air is sent into the packers 63, 63 from the ground through an air pipe (not shown) to secure them to the inner wall surface of the injection well H. At this time, the crack 11s is located vertically sandwiched between the packers 63, 63. A water-stop material supply unit 65 for supplying a water-stop material is connected to the inner pipe 61 at the ground entrance. As the water-stop material, for example, a cement-based water-stop material such as mortar or a water glass-based water-stop material such as sodium silicate is used.

[0060] When water-stopping material is injected into the area between the packers 63, 63 from the water-stopping material supply unit 65 through the inner pipe 61, the water-stopping material also penetrates into the cracks 11s. The water-stopping material that has penetrated into the cracks 11s hardens, thereby closing the cracks 11s. Note that the hardened water-stopping material and packers 63, 63 remain not only in the cracks 11s but also in the injection well H, but these residues are removed using a boring device or the like. By repeating the above procedure, the required number of cracks 11s in the injection well H are closed.

[0061] In the subsequent piping step S131, the ground entrance of the injection well H in which the unnecessary fractures 11s have been blocked as described above is connected to the outlet of the heat transfer medium W in the heat recovery section 5. In this case, the heat transfer medium W pumped from the heat recovery section 5 to the injection well H does not enter the blocked fractures 11s, but is mainly injected into the fractures 11 in the injection region 46. That is, the heat transfer medium W can be selectively injected only into the fractures 11 in the injection region 46, while eliminating the need for the permanent packers 53, 53 in the third embodiment.

[0062] Furthermore, supercritical carbon dioxide may be injected instead of the water-stopping material described above. Supercritical carbon dioxide is carbon dioxide in a supercritical state in the range of 31°C or higher and 7.28 MPa or higher. That is, as shown in FIG. 12(b), a supercritical carbon dioxide supply unit 67 for supplying supercritical carbon dioxide is connected to the inner pipe 61 instead of the water-stopping material supply unit 65. Then, supercritical carbon dioxide is injected from the supercritical carbon dioxide supply unit 67 through the inner pipe 61 into the region between the packers 63, 63.

[0063] The supercritical carbon dioxide injected into the region between the packers 63, 63 penetrates the cracks 11s well due to its high diffusivity. This supercritical carbon dioxide then reacts with calcium ions in the hot dry rock mass G due to its high solubility, precipitating calcium carbonate. The calcium carbonate thus precipitated in the cracks 11s blocks the cracks 11s. In this case, the fixation of carbon dioxide underground can contribute to the prevention of global warming. The raw material for the supercritical carbon dioxide used here may be industrially derived carbon dioxide. Furthermore, since there is no need to use cement-based water-stopping materials or water glass-based water-stopping materials as described above, resource conservation can be achieved.

[0064] The present invention can be implemented in various forms, including the above-described embodiment, with various modifications and improvements based on the knowledge of those skilled in the art. Furthermore, it is also possible to configure modified examples by utilizing the technical matters described in the above-described embodiment. The configurations of the respective embodiments may be used in appropriate combination.

[0065] For example, in the third embodiment, the crack generation step S104 and the judgment S103a described above may be additionally executed. In the embodiment, the heat recovery system 3 designates one of the wells A as an injection well H and the others as production wells J. However, the heat recovery system 3 may designate two or more of the wells A as injection wells H and the others as production wells J.

[0066] The optical fiber sensor 21 installed in the optical fiber sensor installation step S102 may be used to monitor the strain and temperature of the injection well H and the production well J when the heat recovery system 3 is in service.

[0067] Furthermore, in the first testing step S103 in the embodiment, measurement is performed with one well A as candidate injection well h and the other wells A as candidate production wells j, but in the first testing step S103, measurements may be further performed with multiple wells A as candidate injection well h and the other wells A as candidate production well j. Furthermore, measurements may be performed with one well A as candidate injection well h and the other wells A as candidate production well j, or measurements may be performed with one well A as candidate production well j and the other wells A as candidate injection well h. Furthermore, in the well determination step S105, multiple wells A may be determined as injection wells H and the remaining wells may be determined as production wells J. Furthermore, one well A may be determined as injection well H and the remaining wells may be determined as production wells J, or one well A may be determined as production well J and the remaining wells may be determined as injection wells H.

[0068] Furthermore, in the well determination step S105 of the embodiment, all enthalpy values ​​of the heat transfer medium W ejected from all candidate production wells j are used as the evaluation index for heat recovery efficiency, but the evaluation index for heat recovery efficiency is not limited to this. For example, the heat recovery efficiency for each combination of candidate injection well h and candidate production well j may be evaluated using a more complex method. Similarly, in the injection region determination step S113, the heat recovery efficiency corresponding to each injection test region 45 may be evaluated using a more complex method. [Explanation of symbols]

[0069] 11, 11a, 11b, 11c, 11s...fractures, 21...optical fiber sensor, 43...test packer, 45, 45a, 45b, 45c...injection test area, 46...injection area, 53...permanent packer, A, A1, A2, A3, A4, A5...wells, G...hot dry rock, H...injection well, h...potential injection well, J...production well, j...potential production well, W...heat transfer medium.

Claims

1. A heat recovery method for recovering heat from a hot dry rock mass by recovering a heat medium injected into an injection well, passing through the hot dry rock mass, and being discharged from a production well, comprising: a well construction step of constructing a plurality of wells that reach the hot dry rock; a first testing step in which some of the wells are designated as candidate injection wells that are candidates for the injection wells and others are designated as candidate production wells that are candidates for the production wells, and measurements indicating the state of the heat medium discharged from the candidate production wells when the heat medium is injected into the candidate injection wells are repeatedly performed while changing the combination of the candidate injection wells and the candidate production wells; a well determination step of determining injection wells and production wells to be used for heat recovery from among the plurality of wells based on the test results obtained in the first test step; A heat recovery method comprising:

2. The heat recovery method according to claim 1 , further comprising a crack generating step of artificially generating cracks in the hot dry rock mass.

3. an optical fiber sensor installation step of installing an optical fiber sensor in the well that functions as a strain sensor for the well; a crack detection step of detecting positions of a plurality of cracks present in the candidate injection well based on the strain in the candidate injection well detected by the optical fiber sensor; a second test step in which a pair of test packers is installed in the injection well determined in the well determination step at a position that sandwiches a portion of the plurality of fractures detected in the fracture detection step from above and below to form an injection test area sandwiched between the test packers, and measurement values ​​that indicate the state of the heat medium discharged from the production well when the heat medium is injected into the injection test area are repeatedly measured while changing the injection test area; an injection area determination step of determining an injection area to be used for heat recovery from among the plurality of injection test areas in the injection well based on the test results obtained in the second test step; The heat recovery method of claim 1 further comprising:

4. The heat recovery method according to claim 3 , further comprising a packer permanent installation step of installing a pair of permanent packers for permanently forming the injection area determined in the injection area determination step.

5. The heat recovery method according to claim 3 , further comprising a crack plugging step of plugging the cracks present in areas other than the injection area determined in the injection area determining step.

6. The heat recovery method according to claim 5 , wherein the crack closing step injects a water-stopping material into the cracks present in areas other than the injection area.

7. The heat recovery method according to claim 5 , wherein the crack plugging step injects supercritical carbon dioxide into the cracks present in regions other than the injection region.

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