阅读说明：本技术 用于地热井中的热分布控制及能量回收的方法 (Method for heat distribution control and energy recovery in geothermal wells ) 是由 P.凯恩斯 M.特夫斯 J.雷德芬 于 2019-08-08 设计创作，主要内容包括：一种控制地热井横向部分中从脚跟到脚趾的温度最大值和最小值的方法。该方法包括在可能热接触的位置附近设置至少一对井。工作流体在一个方向上在该对中的一个井中循环,且第二井的工作流体在与第一个相反的方向上循环。以这种方式,可以获得温度平衡以缓解最大值和最小值,从而在相应的井和其间的岩石地层区域中产生工作流体的基本上更均匀的温度。公开了具体的操作方案,其涉及用于使热能回收最大化的温度控制。(A method of controlling the maximum and minimum values of temperature from heel to toe in the lateral portion of a geothermal well. The method includes positioning at least one pair of wells in proximity to a location of possible thermal contact. The working fluid circulates in one direction in one well of the pair and the working fluid of the second well circulates in the opposite direction to the first. In this manner, a temperature balance may be achieved to mitigate maxima and minima, thereby producing a substantially more uniform temperature of the working fluid in the respective wells and the rock formation zones therebetween. Specific operating schemes are disclosed that relate to temperature control for maximizing thermal energy recovery.)

1. A method for maximizing geothermal energy recovery within a formation having a geothermal gradient, comprising:

determining a geothermal gradient within a rock volume of the formation;

forming a wellbore configuration for location and positioning within the rock volume, the configuration of the wellbore being based on the determined geothermal gradient for maximum heat recovery, the wellbore configuration comprising a closed loop having an inlet well and an outlet well in fluid communication and a lateral interconnecting portion, the lateral portion of the configuration being positioned within the rock volume;

selecting at least one working fluid to circulate in a predetermined sequence within the configuration based on:

a wellbore configuration;

a geothermal gradient change; and

the geological condition of the stratum;

determining a working fluid temperature from sequential cycles within the wellbore configuration; and is

Selecting at least one of:

a working fluid re-routing and distribution within the configuration;

a working fluid composition;

a working fluid flow rate within the configuration;

a working fluid flow direction; and

a combination thereof to maximize energy recovery from the rock volume with the working fluid.

2. The method of claim 1, wherein the wellbore configuration is formed by sealing a wellbore during drilling of a missing casing in a lateral portion of the wellbore.

3. The method of claim 1, wherein determining the gradient comprises determining a temperature distribution within the rock volume.

4. The method of claim 1, further comprising the step of characterizing rock type and thermal conductivity within the rock volume.

5. The method of claim 1, wherein selecting a working fluid composition comprises incorporating additives to maintain wellbore integrity and fluid density in the configuration to obtain compressive strength of the wellbore configuration.

6. The method of claim 1, further comprising the steps of: controlling at least one of a working fluid temperature, wellbore integrity in the configuration, and thermal recharging of the wellbore in the configuration during operation.

7. The method of claim 1, further comprising the steps of: auxiliary mechanical or chemical unit operations and combinations thereof are optionally introduced to maintain well bore integrity.

8. The method of claim 7, wherein the auxiliary mechanical operation comprises introducing casing and a multilateral junction into the wellbore configuration at a predetermined location.

9. The method of claim 7, wherein the auxiliary chemical operation comprises introducing at least one of a chemical sealant, a densification agent, and a bridging agent into the wellbore configuration at a predetermined location in at least one of a single operation and sequential staged operations.

10. The method of claim 1, further comprising at least one of spacing, angling, stacking, aggregating, staggering, and interconnecting individual wellbores in the configuration, and combinations thereof, to maximize energy extraction.

11. The method of claim 10, further comprising the step of: selectively connecting the entry well and the exit well at predetermined locations in the configuration at one or more above-ground locations.

12. The method of claim 1, wherein the step of forming a wellbore configuration comprises forming a network of wellbores within the rock volume of the formation, the network of wellbores optionally having a common inlet well and a common outlet well connected to the wellbores at an above-ground location.

13. The method of claim 1, wherein the sequential cycles comprise flow rate changes, flow direction, standstill, and combinations thereof.

14. The method of claim 1, further comprising the steps of: sampling the working fluid at a predetermined location within the wellbore configuration to determine a change in composition relative to the non-circulated working fluid.

15. The method of claim 14, further comprising the step of: determining whether the compositional change is associated with a chemical or mechanical wellbore factor.

16. The method of claim 1, further comprising the step of forming the configuration within at least one of: a high temperature gradient, a low temperature gradient, a conductive zone within the gradient, a convective zone within the gradient, a high permeability zone within the formation, a low permeability zone within the formation, and combinations thereof.

17. The method of claim 1, further comprising the step of controlling thermal distribution variations between proximate wellbores in the configuration, the controlling comprising:

selecting the wellbore configuration within the rock volume based on a temperature distribution within the rock volume;

the configured wellbores are spaced to reduce thermal interference and inefficient heat recovery between proximate wellbores.

18. The method of claim 17, optionally comprising the steps of:

introducing a first working fluid into a first well of the wellbore to absorb thermal energy from surrounding formation rock through the well in the gradient from a maximum to a minimum;

introducing a second working fluid into a second well of the wellbore to absorb thermal energy from surrounding formation rock through the well in the formation from a maximum value to a minimum value; the first fluid flow is in an opposite direction to the second fluid flow to induce thermal uniformity within the volume of rock proximate the well, with no thermal minima and maxima.

19. The method of claim 1, further comprising integrating surface equipment with the circuit to utilize the recovered thermal energy.

20. The method of claim 19, wherein the surface device comprises at least one of: steam generation devices for industrial operations, power generation devices, power storage devices, power distribution networks for selectively distributing energy to coupled wellbore configurations, and combinations thereof.

21. The method of claim 1, further comprising the steps of: a drag reducer is introduced into the working fluid to achieve a desired wellbore network configuration while maintaining optimal hydraulic performance.

22. The method of claim 1, further comprising the steps of: sufficient hydraulic friction pressure loss is provided in each lateral portion to passively control flow distribution within the lateral portion within the configuration.

23. The method of claim 1, further comprising the steps of: determining an interaction between thermal conductivity and borehole penetration rate for location and position of the borehole within the rock volume.

Technical Field

The present invention relates to thermal control of thermal energy absorbed in a well, and more particularly to control of efficient energy recovery and temperature dissipation in a geothermal well, and optimization of the design and operation of a closed-loop geothermal well bore system.

Background

Currently, the united states is a global leader of installed geothermal capacity, which has more than 3,300 megawatts in eight states. Most of which are located in the state of california.

It is known that in geothermal energy, heat is continuously generated in the magma layer by radioactive decay. It is reported that the heat in the 10000 meter range of the earth's surface is 5 ten thousand times more than all the oil and gas resources in the world. Clearly, this is a point of interest for energy developer communities.

At these depths, problems with high temperature damage to the equipment have previously been reported. In some cases, these have been alleviated or have been satisfactorily tolerated.

One of the key points in geothermal energy production is to manage heat loss within the well, thereby managing the ability to recover heat using a working fluid that serves as a capture and transport medium.

As shown in said document, the prior art has been developed in this field.

U.S. patent No.5515679 issued to Shulman at 5/14 1996 provides a method for geothermal mining and recovered energy utilization. The manifold device receives a network of wells dispersed within the formation. An array of various formations or wells is provided, with wells dispersed within each particular well formation. This document does not mention heat dissipation over the length of the well.

In U.S. patent No.9556856 issued on 31/1/2017, Stewart et al provides a geothermal energy system and method of operation. In the disclosure with reference to fig. 15, the patentee states:

the "inner tube 304 is centered in the outer sleeve 302 by centralizer fins 318, the centralizer fins 318 being positioned spaced along the tube 304 and remaining" open ended "a short distance above the bottom plug 314, thereby establishing an effective closed loop path for circulation of the working fluid (water-based) as a thermal energy transfer medium. These fins 318 also act as mechanical "turbulators" that induce flow characteristics in the perforated heat exchanger ring 320 between the outer casing 302 and the inner tube 304 that moderately enhance the transfer of geothermal energy to or from the surface formation while minimizing pressure losses. Typically, the working fluid is pumped down the ring 320 (arrow a) and up through the inner tube 304 to the surface (arrow B) under the control of the surface control module, but depending on the precise application, the direction of circulation may be reversed in some cases to provide optimal performance.

This paragraph teaches working fluid flow reversal within a single well, but does not involve any mechanism for controlling thermal problems within the formation undergoing thermal production.

Guodong et al, in Energy 128(2017), page 366-: with a particular working fluid, heat exchange between the hot surrounding rock formations is enhanced by the long horizontal section of the closed circuit well, the increase in horizontal well length and fluid injection rate in the thermal insulation tubing improves production, and the use of multi-branch horizontal sections is beneficial.

In general, the teachings of the prior art are useful, but do not address issues such as: the inherently large footprint of multiple lateral horizontal wells, well-positioned and configured within a given rock formation volume for enhanced thermal recovery or temperature maxima and minima along the well length.

Recognizing these shortcomings, the present technology described herein further advances geothermal technology and combines deterministic unit operations in a unique way to efficiently recover thermal energy within a geothermal gradient, regardless of gradient characteristics and variations, formation porosity, environmental conditions, geographic location, and others.

In the parallel prior art from the oil and gas industry, drilling techniques for multiple lateral wells (multilateral wells), specific drilling fluids, etc. are mature, but simple re-use for geothermal exploration and recovery is not practical or feasible; geothermal energy recovery presents its own complexities. Many factors must be considered to synthesize a viable recovery scheme. This requires the ability to dynamically adjust thermodynamic parameters during energy recovery, alleviate any well integrity or performance issues, reverse, reroute or stop working fluid flow, change working fluid composition, etc. Integration in the correct order requires analysis based on extensive knowledge of a large number of technologies; without this, the solution becomes complicated.

This is evidenced in a myriad of geothermal prior art that have been struggling to address drilling problems, working fluid formulations, complex heat exchanger arrangements with bottom hole and surface positioning, gradient properties and locations, continuous and discontinuous rings, well casing and variations thereof.

Due to the promise of geothermal prior art, techniques that go around them with special complexity to obtain a generic solution would be beneficial.

The present invention provides an effective solution to the current limitations to the following extent: geothermal energy production can economically become the primary energy production method.

Disclosure of Invention

It is an object of the present invention to provide control of the temperature distribution in the rock surrounding a geothermal well.

It is a further object of an embodiment of the invention to provide a method for maximizing geothermal energy recovery in a formation having a geothermal gradient, comprising:

determining a geothermal gradient within a rock volume of the formation;

forming a wellbore configuration for location and positioning within the rock volume, the configuration of the wellbore being based on the determined geothermal gradient to obtain maximum heat recovery, the wellbore configuration comprising a closed loop having an inlet well and an outlet well in fluid communication and a lateral interconnecting portion, the lateral portion of the configuration being positioned within the rock volume;

selecting at least one working fluid to circulate in a predetermined sequence within the configuration based on:

a wellbore configuration;

a geothermal gradient change; and

the geological condition of the stratum;

determining a working fluid temperature from sequential cycles within the wellbore configuration; and

selecting at least one of:

a working fluid re-routing and distribution within the configuration;

a working fluid composition;

a working fluid flow rate within the configuration;

a working fluid flow direction; and

their combination maximises the energy recovery from the rock volume with the working fluid.

The heat transfer from the rock is inversely proportional to the working fluid temperature within the wellbore. The heat transfer maximum occurs at the "foot" of the inlet well, where the temperature of the working fluid in the well is at a minimum. The working fluid is heated as it passes through the horizontal portion of the well towards the "toe" of the well. The thermal profile data indicates this. The heat transfer profile is generally observed to taper from heel to toe with a minimum at the exit well.

It has been found that combining various configurations of wells has a beneficial effect on distribution, allowing higher heat extraction from a given volume of rock, and reducing well construction costs and "dead spots" where heat extraction is inefficient.

It has been found that the staggered arrangement or meshing of the horizontal portions of the proximate wells can compensate for temperature maxima and minima in the wells. This effect is achieved by proximity sufficient for thermal contact between the wells. In the event that the working fluid flows counter-currently between adjacent wells, a temperature equilibrium may be induced in the geothermal formation such that a maximum of one well cancels or mitigates a minimum of the adjacent wells.

To further enhance the extraction of thermal energy from within the formation, a wellbore configuration network may be formed by sealing the wellbore during drilling of an open casing (lost casing) in a lateral portion of the wellbore. This is clearly a significant cost-effective and advantageous thermodynamics. This contributes to the general applicability of the solution; the configuration may be used for any of a high temperature gradient, a low temperature gradient, a conductive zone within a gradient, a convective zone within a gradient, a highly permeable zone within a formation, a low permeability zone within a formation, and combinations thereof.

The sealing composition may also include a material that enhances the thermal conductivity of the seal. Suitable ingredients can generally be found in the known art in Harliberton, Beckhols, Baker Hughes, and the like.

Additionally, the working fluid composition may include additives to maintain wellbore integrity and fluid density in the configuration to achieve compressive strength of the wellbore in the configuration.

Auxiliary mechanical or chemical unit operations and combinations thereof may be included to maintain well bore integrity. This may include using a chemical sealant and a densification agent as needed, which is introduced into the wellbore configuration at a predetermined location in at least one of a single operation and sequential staged operations.

With respect to mechanical operation, the casing/multilateral joint can be bonded at a predetermined location as desired.

Drag reducers or other additives may be added to the working fluid to improve thermodynamic performance, reduce or eliminate parasitic pump loads, and enable drilling of larger wellbore networks while maintaining optimal hydraulic performance.

Furthermore, the method comprises the following steps: sufficient hydraulic friction pressure loss is provided in each lateral portion to passively control flow distribution within the lateral portion within the configuration.

With respect to the wellbore configuration, it may be spaced, angled, stacked, clustered, staggered and interconnected, respectively, and combinations thereof, within the rock volume to maximize energy extraction. Orientation will also alleviate any thermal interference or "dead spots," as well as the potential need for thermal recharging of individual wellbores that may require quiescent working fluid flow to be inactive for a predetermined time frame.

The configured entry and exit wells may be common to at least some of the proximate well configurations. Single or multiple sites are also contemplated. Further, the closed loop of the wellbore configuration may be above or below the surface site. This will depend on the particular situation.

Having thus described the invention in general terms, reference will now be made to the accompanying drawings.

Drawings

FIG. 1 is a temperature profile illustrating temperature at a radial distance from a borehole centerline relative to axial position along a horizontal borehole;

FIG. 2 is a thermal diagram of a radial volume of rock mined to obtain heat for a pair of spaced apart horizontal wellbores;

FIG. 3 is a view similar to FIG. 2, wherein the working fluid flow is reversed for a pair of horizontal well bores;

FIG. 4 is a schematic illustration of a well system having a plurality of horizontal wells commonly connected to an entry well and an exit well;

FIG. 5 is a view similar to FIG. 4 showing a staggered well system according to one embodiment of the invention;

FIG. 6 is a top plan view of an alternate embodiment of the present invention;

FIG. 7 is a cross-sectional view of a well arrangement;

FIG. 8 is a cross-sectional view of another well arrangement;

FIG. 9 is a top plan view of an alternate embodiment of the present invention;

FIG. 10 is a cross-sectional view taken along line 9-9 of FIG. 9;

FIG. 11 is a schematic illustration of a wellbore configuration network within a rock formation;

FIG. 12 is a schematic illustration of a cycle sequence within a wellbore system in a configuration network;

FIG. 13 is a flow chart of events involved in a scenario; and is

FIG. 14 is a closed loop wellbore network placed on a formation temperature profile.

Like numbers used in the figures represent like elements.

Detailed Description

Referring now to fig. 1, a thermal representation is shown depicting a gradual decrease in temperature along an axial location of a horizontal well for a given surrounding rock volume. Of note is the fact that there is heating of the working fluid from the heel to the toes of the well. The heat transfer from the rock is inversely proportional to the working fluid temperature. Thus, most of the thermal energy is captured at the maximum at the heel and the minimum at the toe. This obviously has an efficiency limitation because a maximum and a minimum are created.

Referring now to fig. 2, a plan view of two spaced apart horizontal well bores 10 and 12 disposed in a geothermal formation 14 is shown. Wells 10 and 12 are spaced apart but in thermal contact. In this example, each wellbore 10 and 12 has a flow of working fluid in the same direction as shown in the figures. A thermal profile as discussed with reference to fig. 1 is depicted for each of the wellbores 10 and 12, wherein the profiles diverge from one another, leaving a region 16, i.e., a "dead spot" from which no thermal energy has been extracted for the relevant time period.

Fig. 3 shows a first solution to the extraction problem proposed in relation to fig. 2. In this figure, the flow direction between the horizontal bores 10 and 12 is reversed as shown. In this way, for each wellbore 10 and 12, the temperature maxima and minima are balanced and the volume of rock between the two wellbores 10 and 12 has no "dead" or "unexplored" region, i.e., region 16. Thus, for a given volume of rock in which the boreholes 10 and 12 are located, a greater radial volume of rock may be mined to obtain heat, or in the case of heat, more heat may be recovered per unit area. The boreholes are also spaced closer together, thereby greatly reducing drilling/construction costs.

FIG. 4 is a schematic representation of a multiple lateral or horizontal well system of the prior art, generally designated by the numeral 18. In this embodiment, the horizontal bores 20-32 are in generally radially spaced apart relationship, all sharing a common inlet bore 36 and outlet bore 38. In this embodiment, the length of the horizontal well is, for example, between 2000m and 8000 m.

Fig. 5 shows a staggered or meshed arrangement of two well systems 18. It has been found that thermal contact has the benefit shown in figure 3 where two well systems 18 are provided spaced apart, due to the effectiveness of the arrangement discussed in relation to figure 3. The second well system 18 includes horizontal well bores 38 and 50 and, similar to fig. 4, has a common inlet well bore 52 and a common outlet well bore 54. With this arrangement, the proximate wellbores, e.g., 20, 38; 22, 40; 24,42, etc., each having an opposite working fluid flow direction relative to each other, to achieve the results as described with respect to fig. 3.

It will be appreciated that this greatly increases the well density of a given volume of rock within the geothermal formation, thus increasing the amount of thermal energy extracted into the working fluid.

Turning now to FIG. 6, an alternative embodiment of the present invention is shown in which well systems 18 are arranged side-by-side in an inverted fashion. In this arrangement, the first well system 18 includes a plurality of well bores 56, 58, and 60 that are commonly connected to an inlet well bore 62 and a common outlet well bore 64. From the inlet 62 to the outlet 64, the plurality of wells 56, 58, and 60 converge and thus the spacing therebetween varies from 62 to 64. The working fluid flow direction is shown as being from 62 to 64. Cooperating with the plurality of bores 56, 58 and 60 is a second plurality of bores 66, 68 and 70. Which share a common inlet 72 and a common outlet 74. This arrangement is the same as that of well bores 56, 58 and 60, except that the convergence is opposite to that of first well system 18, i.e., the fluid flow is from 72 to 74. Additionally, the plurality of well bores 66 are spaced apart from, but in thermal proximity to, the plurality of well bores 60. Each well system 18 is coupled at 76 and 78 for fluid exchange therebetween. As mentioned above, this is an alternative arrangement to mitigate the induced maximum and minimum temperature distributions in the rock volume.

FIG. 7 shows a cross-sectional view of 7 multiple wellbores near the exit well at the convergence point discussed in connection with FIG. 6, with the spaced relationship between the multiple wellbores 82-92 shown similarly represented by distance "X", with example distances of 20m to 80 m. The well comes out of the page. Fig. 8 shows a cross-sectional view of 7 porous wells 82 to 92 at divergent points near the entry well, an exemplary spacing "Y" being equidistant between 80m and 120 m.

This arrangement is an alternative to the arrangement discussed with respect to fig. 5, however, it achieves the same thermal benefit due to the fluid flow direction and thermal proximity of the multiple wellbores.

Referring to fig. 9, an alternative embodiment of the arrangement of fig. 6 is shown. In this embodiment, a staggered connection is provided. In this example, the plurality of well bores 96, 98 and 100 have a common inlet well 100 and a common outlet well 102, and diverge from 100 to 102. The plurality of wells 96, 98, and 100 are interleaved with the plurality of wells 104, 106, and 108. Which share a common well bore inlet 110 and a common well bore outlet 112. The well pattern diverges from 112 to 110. The spacing relationship is the same as in the previous embodiment to achieve the heat capture result. Each well system is coupled for fluid exchange at 114 and 116.

FIG. 10 is a schematic diagram of a cross-section of a system of wells 118, 120 and 122 in similar spaced relation and in thermal contact with wells 124, 126 and 128. 118. 120, and 122 are in counter-current to the working fluid flow of wells 124, 126, and 128. The spacing within the wells depends on a number of factors.

Referring now to FIG. 11, a schematic diagram of a planned wellbore configuration network within a rock formation having a variable geothermal gradient is shown and indicated by numeral 130. As shown in the example, the lateral well system is represented by the numeral 18, as referenced by the previously described figures, and may subscribe to any configuration or combination of configurations previously discussed herein. The numerical designations are for clarity only.

With respect to the arrangement of the well system, it may be spaced, angled, stacked, clustered, staggered, interconnected, and combinations thereof within the rock volume to maximize energy extraction. This configuration is achieved once the geothermal gradient is determined, along with the rock thermal conductivity. The flexibility of the method can be further increased by the fact that the drilling of the wellbore can be done while sealing the wellbore missing casing (lost casing). In some particular scenarios, the cannula may be used at a predetermined location within the network.

The configuration may include a discrete closed loop wellbore configuration having an inlet 36 and an outlet 38 and lateral portions 20-32 (shown more clearly in fig. 3) disposed within the gradient 130 and/or it may be interconnected with a common connection of the inlet 36 and outlet 38 between the configurations in the network. The common inlet connection is indicated by the numeral 132 and the common outlet is indicated by the numeral 134. Further, the common outlet 134 or each outlet 38 may be networked to an adjacent or proximate wellbore configuration represented by numeral 136. This is indicated by the dashed line and numeral 138.

The gradient may include a high temperature gradient, a low temperature gradient, a conductive zone within the gradient, a convective zone within the gradient, a high permeability zone within the formation, a low permeability zone within the subterranean formation, and combinations thereof.

Fig. 12 schematically depicts cross-switching of working fluids within a network. In this way, thermal variations or underproductions are avoided in the network of wells. Thus, the working fluid may be routed and distributed within the configuration, the working fluid composition changed entirely or with additives, fluid flow rate changes, direction changes, and combinations thereof to maximize energy recovery from the geothermal gradient using the working fluid. Additionally, depending on performance and/or thermal issues, the working fluid flow may stop completely at a predetermined location within the network. This process also facilitates the hot recharging of the well or its system.

Returning to fig. 11, as shown, the closed loop well 18 may be closed above or below the surface S. This will depend on the environmental conditions and other variables within the purview of the skilled person. Operational controls, such as fluid supply, temperature monitoring, fluid sampling, direction, rate, etc., may be performed at the surface S at 140 using any suitable mechanisms and instruments known in the art to achieve the desired results. The recovered thermal energy may be transferred to a suitable energy converter 142 for distribution and/or storage in a storage device 144 for delayed use. Advantageously, the recovered energy can be used to generate steam for use in an industrial process. The well bore network may be positioned adjacent or near an existing industrial project, as the case may be.

Fig. 13 shows the overall scheme with the various stages depicted. In phases 2 through 4, the sequence of events may vary depending on environmental conditions, geology, gradients, rock type and variability, and the like. The aim is to clarify the benefits of the solution by maximizing the key operations required for heat recovery, which is a clear feature of the present technology, regardless of the conditions.

FIG. 14 illustrates how the presented previous concepts may be placed in the context of a variable temperature distribution within a target formation, which is illustrated by an isotherm profile. The optimal well bore network configuration, spacing between lateral sections, flow direction and flow rate vary according to the geothermal gradient and temperature distribution of the target zone.

Reference will now be made to examples of schemes.

Typically, the first step in optimizing a closed loop system is to determine the geothermal temperature gradient in the area. The gradient is typically between 28-35 ℃/km in the deposition basin, but can increase to 50 ℃ in deposition basins with shallow curie point depths (thin shells) and can reach 150 ℃/km in regions with high heat flux.

A target area is identified for placement of a geothermal wellbore. Unlike traditional geothermal techniques, any rock is a usable area for a closed loop system because permeability, porosity or rare geological features are not required. The target area may be sandstone, shale, siltstone, mudstone, dolomite, carbonate, or crystalline bedrock.

Some target areas are preferred due to the combination of temperature distribution, thermal conductivity, and borehole penetration rate. The next step is therefore to use the geothermal gradient to determine the temperature distribution of the rock volume, as shown in fig. 14, which shows a top view of the temperature contour (isotherm) of a given formation. Suitable temperatures may be from 85 ℃ to 250 ℃ or up to 350 ℃.

The thermal conductivity distribution within the rock volume is estimated. This may be based on direct measurements, extrapolated laboratory data, or calculated from indirect data, such as sound velocity, mineralogy, or rock type. Thermal conductivity ranges from 1.7W/m K for soft shale to greater than 4W/m K for quartz-rich sandstone.

The next step is to determine the infinite compression strength (UCS) of the target region and then estimate the drilling rate of penetration, which is a strong function of the infinite compression strength.

Traditional geothermal techniques involve searching for hot liquid areas and then optimizing the planning and development of resources. Rather, since any geological formation is suitable for use in a closed-loop system, the target zone selection may be based in part on the drilling rate of the optimal penetration. UCS controls the rate of penetration, typically in the range of 40MPa for weak shales and up to 300MPa for crystalline bedrock. The rate of penetration on drilling is typically 5m/h for hard rock and 300m/h or more for soft rock.

All mechanical and chemical unit operations are considered to maintain the well bore integrity of a closed loop system. The rock type and infinite compressive strength will to a large extent determine the best solution. It is determined whether the sealant and/or working fluid additive is sufficient, or whether a sleeve and/or mechanical connection is required, or any combination of these.

In the case of a large number of identified subsurface design inputs, the next step is to analyze the temperature-dependent energy distribution required by the end user. This may be a combination of thermal, cooling or electrical power, or a distribution of combinations thereof. Typically, the distribution varies throughout the day and throughout the season. Likewise, the surface site's environmental conditions and time-based pricing may vary throughout the day and season, and optionally may be analyzed.

The three-dimensional wellbore network configuration is designed to maximize useful energy extraction from the rock volume. Part of this design involves determining the relative spacing between the boreholes in the network to minimize thermal disturbances and "dead spots", or areas in the rock volume where energy cannot be efficiently extracted. The optimum spacing is a function of the temperature distribution, thermal conductivity, and working fluid properties and flow rate in the target region. Drilling costs must also be considered. The spacing between the boreholes is typically between 20 and 120 meters. The spacing between adjacent wellbores in the network may be varied along the length of the wellbore to maximize performance, minimize interference, and minimize "dead spots".

The well bore network configuration is also designed to provide sufficient hydraulic friction pressure loss in each lateral section to passively control flow distribution between the various lateral sections within the configuration.

Surface equipment should be integrated into the system design because the outlet from the surface infrastructure is simply the input to the subsurface closed loop system. Thus, the design and performance of surface facility equipment can have an impact on subsurface design and performance, and vice versa. For example, a heat engine with an outlet temperature of 70 ℃ will have a different optimal subsurface wellbore network design than a heat engine with an outlet temperature of 90 ℃.

The composition of the working fluid within the wellbore network is determined over time along with the optimal flow rate. The working fluid composition is selected to achieve optimal thermodynamic performance and to maintain wellbore integrity. The working fluid may be water, a supercritical fluid, a hydrocarbon, a refrigerant, or any other fluid. The wellbore integrity additive may include a sealant, a reactant, a solid particulate, a bridging agent, a plugging material, a densifier component to maintain sufficient compressive strength on the wellbore, or any combination. Drag reducers may be added to the working fluid to achieve larger wellbore network configurations without reaching hydraulic limits or affecting overall thermodynamic efficiency.

The working fluid circulates in the network. The flow rate through the network of series connected wellbores is typically between 40L/s and 200L/s water equivalent. If the well network is arranged with parallel well loops or a combination of well loops in series or parallel, the total flow rate is scaled accordingly.

Thermal energy is recovered from the working fluid circulating through the closed loop wellbore network. Alternatively, traffic may be redistributed within the network to maximize performance.

The recovered energy is distributed, stored, and/or converted into electricity. The conversion and storage between the various forms of energy may be determined by end user requirements and/or dynamic pricing.

During operation, fluid temperature and composition anomalies are monitored, optionally thermal distributions of wellbores in the network are monitored and/or estimated, and optionally wellbore integrity of wellbores in the network is monitored and/or estimated.

Based on real-time monitoring and estimation, operations may be implemented to optimize thermodynamic performance. These include, for example, variations in flow velocity, flow direction, and flow distribution between wellbores in the network. For example, the outlet fluid temperature in one portion of the network may be higher than expected, while the fluid temperature in another portion of the network may be low; the flow rate can be adjusted accordingly.

Wellbore integrity can be monitored via measured pressure drops across the wellbore network, measured working fluid volume balance (leakage or increase in volume), compositional changes, and resulting solids volumes and characteristics. Dynamic repair of the wellbore may be initiated, for example, using working fluid additives, reactants, or by circulating a fluid slug containing a sealant, bridging agent, or plugging material.

It should be understood that the above unit operations may be performed in series, or in parallel in an integrated iterative process, or in combination.