Geothermal well steering

Abstract

Technologies for controlling tortuosity of fluid flow through a subterranean formation include introducing a diverting fluid into a wellbore, introducing a first fluid into the wellbore, collecting a second fluid from the wellbore or a second wellbore, and recovering heat from the second fluid. Technologies for increasing the likelihood that a fluid absorbs heat as flowing through a rock fracture include introducing a first fluid into a first wellbore, introducing a particulate fluid into the first wellbore, collecting a second fluid from a second wellbore, and recovering heat from the second fluid. Technologies for recovering heat from a subterranean formation include observing a first parameter of a first fluid introduced into a first wellbore, observing a second parameter of a second fluid collected from a second wellbore, recovering heat from the second fluid, and introducing a diverting fluid into the first wellbore.

Description

[0001] Cross - reference to related applications

[0002] This application claims priority to U.S. Provisional Patent Application No. 63 / 378,612, entitled "Intentional Diversion for Geothermal Wells", filed on October 6, 2022, the entire content of which is incorporated herein by reference. Background Art

[0003] This section is intended to introduce to the reader various aspects of the art that may be relevant to various aspects of the present technology, which are described and / or claimed hereinafter. It is believed that this discussion will help to provide background information to the reader to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light and should not be construed as any form of admission.

[0004] Hot dry rock (HDR) reservoirs represent a great potential for geothermal energy resources as these resources exist in multiple basins around the world. Different from traditional hydrothermal energy systems, HDR reservoirs lack natural flow that can feed hot water to geothermal power plants and they require continuous injection of fluid, typically water. The fluid is usually pumped through multiple injection wells and absorbs heat as it travels through the reservoir towards the production wells, where the energy (as a function of temperature and flow rate) is converted into electricity by a geothermal / hydrothermal power plant. During this process, the injection of cold water under high pressure tends to create new fractures or open existing natural fractures in the reservoir. The common practice is to drill a well, stimulate it with hydraulic fracturing or proppant fracturing, and monitor the location of fracture growth through microseismic measurements. Once the stimulated area is identified, the injection is temporarily stopped and a production well is drilled through the identified area. Such a workflow ensures that when the injection of cold water is resumed later, the water spreads into the previously identified fracture network and further into the production well. As the water travels through the fracture network towards the production well, the water is heated by the geothermal energy of the reservoir.

[0005] One challenge in HDR reservoir exploitation is short - circuiting, which occurs when the flow of water from the injection well to the production well is restricted to a few short paths (or even a very single path). As a result, the water cannot absorb enough heat before production, thus affecting the efficiency of the geothermal / hydrothermal power plant. Therefore, it is necessary to ensure multiple flow paths into the reservoir to improve the heat sweep efficiency. That is to say, if the connectivity between the injection well and the production well is too high, the fluid does not have time to capture enough heat, and the well is described as short - circuited. Summary of the Invention

[0006] The following presents an overview of the specific embodiments described herein. It should be understood that these aspects are presented only to provide a brief overview of these specific embodiments for the reader and are not intended to limit the scope of the present disclosure.

[0007] Embodiments herein relate to systems, devices, compositions, and methods for controlling the tortuosity of fluid flow through a subterranean formation penetrated by at least two wellbores, the method including: introducing a diversion fluid containing a diverting agent into a first wellbore, introducing a first fluid into the first wellbore, collecting a second fluid from a second wellbore, and recovering heat from the second fluid. The diverting agent is degradable and may include particles, fibers, or a combination thereof. The diverting agent may remain in a solid phase at 250°F for at least 10 hours. The diversion fluid and the first fluid may include thickening agents. The subterranean formation includes sedimentary rock, igneous rock, metamorphic rock, or a combination thereof. Collecting the second fluid includes measuring the temperature, pressure, or both of the second fluid, and the measurement is used to control the introduction of the diversion fluid. A system, device, composition, and method for increasing the likelihood that a fluid will absorb heat when flowing through a rock fracture between two wellbores penetrating a subterranean formation.

[0008] Embodiments herein relate to systems, devices, compositions, and methods for recovering heat from a subterranean formation penetrated by at least two wellbores, the method including: observing a first parameter of a first fluid introduced into a first wellbore, observing a second parameter of a second fluid collected from a second wellbore, recovering heat from the second fluid, and introducing a diversion fluid containing a diverting agent into the first wellbore. Observing the first fluid and the second fluid includes measuring the temperature, pressure, volumetric flow rate, chemical composition, or a combination thereof of the second fluid. Some examples may observe the heat recovered from the second fluid.

[0009] Embodiments herein relate to systems, devices, compositions, and methods for controlling the tortuosity of fluid flow through a subterranean formation penetrated by a wellbore.

[0010] Various improvements may be made to the above features with respect to the various aspects of the present disclosure. Additional features may also be incorporated into these various aspects. These improvements and additional features may exist individually or in any combination. For example, the various features discussed below with respect to one or more of the illustrated embodiments may be incorporated individually or in any combination into any of the above aspects of the present disclosure. The brief overview presented above is intended to familiarize the reader with certain aspects and background of the embodiments of the present disclosure without limiting the claimed subject matter. BRIEF DESCRIPTION OF THE DRAWINGS

[0011] Aspects of the present disclosure may be better understood after reading the following detailed description and with reference to the drawings, in which:

[0012] Figure 1 is a cross-sectional view of a formation having particles and fibers;

[0013] Figure 2 is a cross-sectional view of multiple wellbores in a subterranean formation through a fracture network having a fluid flow path;

[0014] Figure 3 is a cross-sectional view of a formation having particles and fibers;

[0015] Figure 4 is a cross-sectional view of a formation having particles and fibers; and

[0016] Figure 5 is a series of cross-sectional views 5(a), 5(b), and 5(c) of multiple wellbores through a subterranean formation. DETAILED DESCRIPTION

[0017] One or more specific embodiments of the present disclosure will be described below. The described embodiments are merely examples of the currently disclosed technology. Additionally, to provide a brief description of these embodiments, not all features of the actual implementation may be described in the specification. It should be understood that, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developer's specific goals when developing any such actual implementation, such as compliance with system-related and business-related constraints, which may vary with the implementation. Moreover, it should be understood that such development work may be complex and time-consuming, but it will still be a routine task in design, fabrication, and manufacturing for those of ordinary skill in the art who benefit from the present disclosure.

[0018] When introducing elements of the various embodiments of the present disclosure, the articles "a," "an," and "the" are intended to mean that there is one or more of the recited elements. The terms "comprising," "including," and "having" are intended to be inclusive and mean that there may be additional elements other than the recited elements. Additionally, it should be understood that references to "one embodiment" or "an embodiment" of the present disclosure are not intended to be construed as excluding the existence of additional embodiments that also incorporate the recited features.

[0019] Controlling the tortuous flow of fluid on the rock surface of an HDR is desirable for effective geothermal well management. In some cases, stimulation of the reservoir (hydraulic fracturing) is required and a diversion fluid is introduced to achieve controlled connectivity between injection and production wells, thereby facilitating a complex fracture network. The embodiments herein rely on intentional multiphase fluid diversion techniques to achieve the generation of a complex fracture network within a geothermal system. The embodiments herein are different from traditional hydraulic fracturing systems in that there may be no particles, including proppants or other solid particles, in the fractures, and diversion can be generated by bridging particles followed by fibers, a mixture of bridging particles and fibers, or only by fibers.

[0020] Some embodiments of the present disclosure relate to a method for creating multiple flow paths in a subterranean formation by pumping a fluid into a reservoir, pumping a portion of bridging particles or other solid particles that will bridge in a main flow path, pumping fibers that will accumulate on top of the bridge, reduce permeability, and significantly slow flow across the bridge, and pumping subsequent fluid that is directed toward secondary flow paths within the reservoir. Some embodiments benefit from methods of pumping a fluid into a subterranean formation to create fractures and carrying some particles to the tips of the fractures such that the particles bridge deep into the formation. The particles are then followed by fibers that reduce the permeability of the particle bridge at the fracture tip (see Figure 1 ), and then more particles are pumped into the fracture. Figure 1 FIG. is a schematic illustration of pumping particles 610 into the formation, followed by pumping fibers 620 into the formation. That is, embodiments of the present disclosure relate to a method of redirecting flow within a reservoir by using materials (fibers or bridging particles and fibers, Figure 2 ) such that the materials are first transported into the main flow path or fracture and accumulate and block the main fracture somewhere along the path. Thus, the materials redirect subsequent flow toward secondary flow paths, thereby improving the thermal sweep efficiency in the reservoir. Figure 2 A cross-sectional view of a formation, a power plant, an injection well, and a production well is provided.

[0021] Figure 5 A series of bird's-eye cross-sectional views of a formation having multiple wellbores is also provided; it shows the operation of geothermal injection and production wells. Figure 5 (a) shows that all heat recovery zones are cooled uniformly. Figure 5 (b) shows a geothermal injection and production well configuration where some areas (shown in white) have excessive fluid flow, making them much colder than the surrounding rock. This results in poor heat recovery. This situation can be identified by monitoring the fluid temperature in the production well. Figure 5 (c) shows that degradable or non-degradable diverter materials are placed in these cooled areas to reduce flow, thereby reheating them to the desired operating temperature again. The diverter materials can be injected from the production well or the injection well. The frequency, volume, degradation rate, and plugging ability of the diverter materials are optimized based on the specific properties of each heat recovery zone.

[0022] Monitoring the fluid flowing from the second wellbore to the energy recovery system can provide information for overall system management. Some embodiments can benefit from distributed thermal sensors across the subterranean formation. Some embodiments control the thermal sweep efficiency.

[0023] · Pumping cold water into the reservoir at a high rate through an injection well;

[0024] ·Monitoring process efficiency by measuring the energy recovered from the production well (fluid flow rate and heat); and / or

[0025] ·Based on the results of the monitoring and typically when needed, pumping diverter pellets of multiple phases, multiple particle sizes and shapes into the formation to form multiple flow paths and improve thermal sweep efficiency.

[0026] Additionally, in some embodiments, a thermal sweep efficiency monitoring method can be established at the production well to measure the total energy brought to the surface (e.g., by monitoring flow rate and heat). When the energy is too low due to short - circuiting or cooling in the reservoir, new diverter material pellets can be pumped to increase the flow path complexity in the reservoir and improve thermal sweep efficiency. Some embodiments can benefit from controlling the temperature of the water when adding it to the initial wellbore.

[0027] Additional embodiments herein relate to increasing thermal sweep efficiency in a subterranean formation by monitoring the energy recovered from a geothermal production well and when the energy is below a pre - determined threshold of the geothermal facility:

[0028] ·Pumping a portion of bridging particles into an injection well, wherein the portion of bridging particles will bridge in the main flow path.

[0029] ·Pumping a portion of fibers that will accumulate on top of the bridge, reduce permeability and prevent water flow across the bridge.

[0030] ·Pumping subsequent fluids directed towards a secondary flow path within the reservoir; and monitoring the efficiency of diversion by measuring the energy recovered from the geothermal well.

[0031] When water is injected into the formation at a high rate, it can follow a preferential path slanting towards the production well, which is less efficient in terms of thermal sweep efficiency. Once the diverter is injected, it blocks the original flow path with a thick solid line and forces the fluid through a more complex flow path. Additionally, the arrival temperature, pressure or both of the fluid at the production well can be monitored. Information from the monitoring, measurement observations can be used to control the introduced diversion fluid by changing the flow, pressure, temperature or composition of the introduced fluid. If the temperature is below the desired temperature, it means there is a short - circuit and diverter pellets may be needed. Alternatively, a tracer can be injected and its concentration monitored at the production well. If the travel time of the tracer is shorter than expected, diverter pellets may be needed. In some embodiments, the degradation products of the diverter or an embedded tracer within the diverter can be monitored at the production well, and if it drops below a certain value, additional diverter needs to be injected.

[0032] In some embodiments, the concentration of fiber degradation products such as lactic acid (a product of PLA degradation) in produced water can be measured. In some embodiments, basic tests need to be performed to ensure that the degraded PLA or other degradation products do not deposit in the production well when transported to the surface, or do not interact with the equipment used for water transportation and the gas turbines that generate electricity on the surface.

[0033] In some embodiments, the diversion materials can be pumped simultaneously and uniformly. In embodiments where the first bridging material and the second bridging material are introduced into the fracture simultaneously, they can be mixed and form a bridge. This is shown Figure 3 in reference numeral 620. In such embodiments, the first bridging agent and a plurality of fibers suspended in a carrier fluid are pumped into the far-field region and thus placed near the outer boundary (periphery) of the growing fracture. The bridging fibers and the fibers are mixed and form a plug. As described above, the size of the bridging particles can be large enough to bridge near the fracture tip. In one or more embodiments, the bridging particles can have a multimodal distribution.

[0034] In some embodiments, the fibers degrade in a manner that can be customized based on rock heat transfer properties such as rock temperature, rock thermal conductivity, and the fracture network geometry that defines the heat wave and configuration. In some embodiments, the subterranean formation includes sedimentary rock, igneous rock, metamorphic rock, or a combination thereof. The bridging particle size and concentration can be selected based on the fracture geometry, mainly the fracture width. In some embodiments, when the concentration of the added fluid is above 1 pound per gallon, the bridging particle size must be greater than the fracture half-width.

[0035] The degradable material is effective in some embodiments because once the reservoir is reheated, one may want to resume injection in that flow path. Some embodiments can optimize the degradation time to match the reservoir reheating time. This will simplify surface operations because one can continuously inject water and periodically inject the degradable diversion agent according to a set schedule. The degradation time will be designed to ensure that the fluid flows to the correct part of the reservoir each time.

[0036] Any degradable or soluble material (bridging particles or fibers or both) must degrade slowly enough to provide sufficient bridging during its placement. The time scale for placement, heating to a specific temperature, can be obtained based on fracture simulations and based on real-time temperature measurements performed by downhole gauges or by monitoring the hydrothermal content in the production well. Some embodiments can benefit from existing various modeling packages commonly used to model heat transfer and temperature evolution in the reservoir and within the fracture network.

[0037] After the formation of the bridging between the particles and the fibers, it may undergo complex evolution in terms of degradation. Degradation is generally closely related to the temperature inside the fracture. The temperature inside the fracture is defined by the balance between the heat inflow (geothermal heat from the reservoir) and the heat outflow (carried by the circulating water). In some embodiments, the actual degradation of the diversion material can be modeled in advance and can be used to design treatments and to select the bridging material or the fibers or both. In some embodiments, the plug made of solid degradable particles (such as fibers) maintains mechanical strength and effectively diverts until about 50 mass% of the starting material degrades. Some embodiments can be understood by how the degradation or dissolution data of any degradable material (perhaps the bridging particles of the fibers) used to obtain the material for diversion in the laboratory is obtained experimentally.

[0038] Figure 1 and Figure 3 A schematic diagram of a formation having particles and fibers is provided for comparison. Figure 1 Depicts two diversion materials being evenly placed in fracture 600, where a first plurality of bridging materials and a second plurality of bridging materials are introduced in sequence. In such embodiments, a first diversion material delivery device including the first bridging material 610 is evenly placed on the outer periphery of fracture 600. The first bridging material 610 can bridge near the fracture tip and form a plug. In such embodiments, the first bridging material can be large particles. The size of the bridging material can be 100 mesh or 40 / 70, or 30 / 50 or 20 / 40 or 16 / 30 or 16 / 20. Fibers can be added to the first bridging material 610 (such as proppant) for better delivery, but this is not necessary. The second bridging material 620 (such as, for example, cellulose fibers dispersed in a carrier fluid) can be delivered to the fracture tip and can accumulate on the surface of the bridge formed by the first bridging material 610 and form a low-permeability plug having a high resistance to fluid flow. Since the fluid no longer flows into the fracture, the fracture extension is restricted. If desired, such embodiments can include more diversion stages (not shown). In embodiments where the first bridging material is sand and the second bridging material is a plurality of fibers, the fibers can be introduced in an amount that is 5 - 100 wt% less than the amount of sand.

[0039] In fact, degradable materials are only one option among the options of particles (such as fibers and particles) considered in this article. Another option is non-degradable materials. In fact, at temperatures above 350°F, each material can degrade or dissolve in some way or form, but this may be a slow process. Degradable materials that degrade slowly over time (days, weeks, months, or several months) can have additional benefits, although the degradation rate depends to a large extent on the water temperature. Some embodiments may have materials that remain in the solid phase at a temperature of 250°F for 10 hours. After the treatment is completed and the injection begins, the deflector at the flow path with the highest flow rate (such as when the water does not have time to be heated too much) degrades more slowly than the deflector at the low-rate flow path. Therefore, in some embodiments, the system is self-adjusting and favors the flow path that enables good heat extraction through circulating water.

[0040] In some embodiments, the fibers and bridging particles are made of insoluble and non-degradable materials. In some embodiments, the fibers are made of soluble or degradable materials, where dissolution or degradation occurs slowly over days or weeks at reservoir temperature. Sometimes, the rate of fiber degradation or dissolution increases with temperature.

[0041] The first bridging agent can be selected from a group of inert non-deformable bridging materials, while the second bridging material can be selected from a group of natural-derived fibers (such as cellulose fibers). Figure 1 Depicts the mechanism that restricts the growth of fracture height and / or length when two bridging materials 610 and 620 are pumped sequentially into the far-field region of the fracture 600. Figure 1 Shows the formation of a plug formed by the first bridging material 610 (such as bridging particles), and the second bridging material 620 (such as fibers) accumulates on top of the plug and forms a low-permeability plug 640. The bridging particles 610 can provide effective bridging due to their larger particle size, while the second bridging material can provide the formation of a layer with very low permeability to provide an overall high resistance to fluid flow, thereby achieving effective far-field diversion.

[0042] It is also conceivable that the first bridging material 610 can be mixed with the first plurality of fibers 620 and form a plug 650, as Figure 3As shown. In such embodiments, a second bridging material 660 (such as a second plurality of fibers) may accumulate on the surface of the plug 650 formed by the first bridging material 610 and the first plurality of fibers 620 and form a low-permeability plug. In such embodiments, the first plurality of fibers 620 may be selected from a group of organic polymers. As described above, the first bridging material 610 may be large enough in size to bridge the far-field region. It is also contemplated that the first bridging material 610 may have a unimodal distribution and / or a multimodal distribution. In such embodiments, the first plurality of fibers 620 and the second plurality of fibers 660 may be the same, having the same length and diameter, or may be different.

[0043] The diverter pellets help to limit crack tip growth. The diverter pellets may consist of particles (bridging material) followed by fibers to reduce permeability. The pellets may also consist of a mixture of fibers and particles followed by fibers or fibers.

[0044] The chemical properties as well as the shape, size, and concentration of the fibers can be tailored based on the temperature profile at the expected location of fiber accumulation downhole (in front of the bridge formed by the bridging particles). The fiber length can range from 0.1 mm to 50 mm, where the aspect ratio (length to width ratio) can range from 2 to 10,000. The concentration of fibers pumped during the operational stage can vary within the range of 0.1–1000 ppt. Additionally, the fiber material can be any polymer fiber, such as cellulose fiber. The amount of fibers pumped during the stage can vary within the range of 10–30,000 pounds. The first and second stages of the fracturing operation can be pumped sequentially one after another or can be spaced apart with a clean fluid or a stage containing particles. The stages can be pumped at the start of the cycle, during the cycle, or after the cycle.

[0045] Similarly, the bridging particles can have geometric considerations. The bridging particles can have a bimodal distribution, as Figure 4 shown. Figure 4 A schematic diagram of various particle size distributions in a formation is provided.

[0046] Figure 4Represents a mechanism for bridging the far - field region when multiple fibers 910 are mixed with bridging materials having a bimodal distribution, such as large bridging particles 920 and small bridging particles 930, respectively. In such embodiments, the bridging material can be pumped early in the particle handling section. As these materials are transported through the fracture towards a narrower fracture width, the larger particles will begin to bridge, and the smaller particles will begin to seal with the fibers in a manner similar to the filtration of the bridging particle system. Fibers with a smaller length can efficiently block the pore space in the seal and provide low permeability to the seal, thereby preventing crack tip propagation. Additionally, the fibers 910 can transport the corresponding large bridging particles 920 and small bridging particles 930 towards the crack tip and form a low - permeability blockage 950. The fibers can also act as bridging fibers and permeability - reducing fibers.

[0047] In some embodiments, the plugging fibers are in - situ generated by polymer precipitation triggered downhole or at the wellhead. Some embodiments can benefit from pumping particles and fibers of at least two different sizes to plug fractures in a specific region of the formation, thereby controlling fracture growth. Some embodiments can use a shrinkable material with multiple particles, where the mixture forms a plug for at least one fracture in the region away from the wellbore, in the fracture aperture. Some embodiments can benefit from using a mixture of particles and degradable fibers, where the degradable material forms a plug in at least one perforation, fracture, or wellbore, and where the fibers eventually at least partially degrade, thus the plug disappears.

[0048] As part of the treatment, the bridging particles and fibers are mixed at the surface and pumped downhole. When the bridging particles are made of materials with a specific gravity above 1.1 (sand, ceramic particles, etc...), a viscosifier can be used to achieve customized material placement. The viscosifier can be a linear or cross - linked guar - based gel, a viscoelastic surfactant - based fluid, xanthan gum, various types of polyacrylamide friction reducers, etc. Similarly, the viscosity requirements (in cP) are similar to those of fluids in a lower temperature range; however, it is difficult to achieve a comparable viscosity level at high temperatures. For some embodiments, the methods to achieve a high viscosity that is stable at high temperatures are to increase the polymer loading, use high - temperature cross - linkers, and use fibers for controlled particle transport.

[0049] During the treatment, the growth of the fracture can be closely monitored through microseismic monitoring, partly to characterize or confirm the formation of new channels in the formation. In some embodiments, the location of new wells is periodically notified, and the location is purely based on the results of the microseismic monitoring. Optical fibers can provide another method for monitoring.

[0050] Although the foregoing description has been made with reference to specific means, materials and embodiments, it is not intended to be limited to the details disclosed herein; rather, it extends to all functionally equivalent structures, methods and uses, such as are within the scope of the claims.

Claims

1. A method for controlling the tortuosity of fluid flow through a subterranean formation penetrated by at least two wellbores, the method comprising: Introducing a diversion fluid containing a diverting agent into a first wellbore; Introducing a first fluid into the first wellbore; Collecting a second fluid from a second wellbore; And Recovering heat from the second fluid.

2. The method of claim 1, wherein the diverting agent degrades.

3. The method of claim 2, wherein the diverting agent comprises particles, fibers, or a combination thereof.

4. The method of claim 2, wherein the diverting agent remains in a solid phase at 250°F for at least 10 hours.

5. The method of claim 1, wherein the subterranean formation comprises sedimentary rock, igneous rock, metamorphic rock, or a combination thereof.

6. The method of claim 1, wherein collecting the second fluid comprises measuring the temperature, pressure, or both of the second fluid.

7. The method of claim 6, wherein the measurements are used to control the introduction of the diversion fluid, the introduction of the first fluid, or both.

8. A method for increasing the likelihood that a fluid will absorb heat as it flows through a rock fracture between two wellbores penetrating a subterranean formation, the method comprising: Introducing a first fluid into a first wellbore; Introducing a particulate fluid containing particles into the first wellbore; Collecting a second fluid from a second wellbore; And Recovering heat from the second fluid.

9. The method according to claim 8, wherein the method further comprises: Introducing a fibrous fluid containing fibers into the first wellbore.

10. The method of claim 9, wherein the fibrous and particulate fluids are introduced simultaneously.

11. The method of claim 8, wherein the particles remain in a solid phase at 250°F for at least ten hours.

12. The method of claim 8, wherein the particulate fluid further comprises a thickening agent.

13. A method for recovering heat from a subterranean formation penetrated by at least two wellbores, the method comprising: Observing a first parameter of a first fluid introduced into a first wellbore; Observing a second parameter of a second fluid collected from a second wellbore; Recovering heat from the second fluid; and Introducing a diversion fluid containing a diverting agent into the first wellbore.

14. The method of claim 13, wherein the diverting agent degrades.

15. The method of claim 13, wherein the diverting agent comprises particles, fibers, or a combination thereof.

16. The method of claim 14, wherein the diverting agent remains in a solid phase at 250°F for at least 10 hours.

17. The method of claim 13, wherein observing the second fluid comprises measuring the temperature, pressure, volumetric flow rate, chemical composition, or a combination thereof of the second fluid.

18. The method of claim 13, wherein observing the first fluid comprises measuring the temperature, pressure, volumetric flow rate, chemical composition, or a combination thereof.

19. The method according to claim 13, the method further comprising: Observing the heat recovered from the second fluid.

20. A method for controlling the tortuosity of fluid flow through a subterranean formation penetrated by a wellbore, the method comprising: Introducing a diversion fluid containing a diverting agent into the wellbore; Introducing a first fluid into the wellbore; Collect a second fluid into the wellbore; and Recover heat from the second fluid.

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