NZ764718B2 - Method for thermal profile control and energy recovery in geothermal wells - Google Patents

Abstract

method for controlling temperature maxima and minima from the heel to toe in geothermal well lateral sections. The method includes disposing at least a pair of wells proximately where thermal contact is possible. A lateral section which connects the wells is formed directly in the rock volume and sealed during drilling without utilizing casing. Working fluid is circulated in one well of the pair in one direction and the working fluid of the second well is circulated in as direction opposite, to the first. In this manner temperature equilibration is attainable to mitigate maxima and minima to result in a substantially more uniform temperature of the working fluids in respective wells and the rock formation area there between. Specific operating protocol is disclosed having regard to the temperature control for maximizing thermal energy recovery. sealed during drilling without utilizing casing. Working fluid is circulated in one well of the pair in one direction and the working fluid of the second well is circulated in as direction opposite, to the first. In this manner temperature equilibration is attainable to mitigate maxima and minima to result in a substantially more uniform temperature of the working fluids in respective wells and the rock formation area there between. Specific operating protocol is disclosed having regard to the temperature control for maximizing thermal energy recovery.

Description

METHOD FOR THERMAL PROFILE CONTROL AND ENERGY RECOVERY IN GEOTHERMAL WELLS TECHNICAL FIELD The present invention relates to thermal control of absorbed thermal energy in wells and more, ularly, the t invention s to control of temperature dissipation and efficient energy recovery in geothermal wells, and optimization of the design and operation of closed-loop geothermal wellbore systems.

BACKGROUND ART tly, the United States is a global leader in installed geothermal capacity having more than 3,300 megawatts in eight states. The majority of this is located in California.

As is known, in geothermal energy heat is ually generated within the magma layer through radioactive decay. It has been reported that the amount of heat within 10,000 meters of Earth's surface contains 50,000 times more energy than all the oil and natural gas resources in the world. Clearly, this is a point of interest within the energy developer community.

At these depths, issues were previously reported concerning the high temperatures damaging ent. These have been, in some cases, mitigated or have become satisfactorily tolerable.

[One of the key points in geothermal energy production is ng the thermal losses within the well and thus the ability to mine the heat with the working fluid used as the e and transport medium.

The prior art has developed in this area as evinced by the documents set forth.

Shulman, in United States Patent No. 5515679, issued May 14, 1996, provides a method for geothermal heat mining and utilization of the recovered energy. A manifold arrangement receives a k of wells dispersed within a formation. Various formations or arrays of the wells are provided, with the wells being dispersed within each specific well formation. The document is silent in respect of the thermal dissipation over the length of the wells.

In United States Patent No. 9556856, issued January 31, 2017, Stewart et al., provide a geothermal energy system and method of operation. In the disclosure in referring to Figure 15, the patentees state: “The inner tubing 304 is centralised in the outer casing 302 by means of centraliser fins 318 which are located at intervals along the tubing 304 and is left “open- ended” a short ce above the bottom plug 314 so as to ish an efficient, closed—loop path for the circulation of the working fluid (water-based) that acts as the thermal energy er medium. These fins 318 also act as mechanical “turbulators” that induce flow characteristics in the borehole heat exchanger annulus 320 between the outer casing 302 and inner tubing 304 that moderately enhance the transfer of rmal energy to or from the ground formations while minimising pressure losses.

Typically, the working fluid is pumped down the s 320 (arrow A) and back up the inner tubing 304 (arrow B) to surface under the control of the surface control module although, based upon the precise application, the circulation ion may be reversed in some cases to provide optimum performance. ” WO 34024 This passage teaches a working fluid flow reversal within a single well, but does not address any mechanism for controlling the thermal issues within the formation where heat mining is being conducted. g eta|., in h r I xli infr h r k v' r issignin a horizontal well, Energy 128 (2017) p366—377, conclude that heat exchange is enhanced between the hot nding rock ion through long horizontal segments of a closed loop well using specific working fluids, an increase in the horizontal well length and fluid injection rate in thermally insulted tubing increase the heat mining rate and that there are benefits to using multi branch horizontal segments.

Collectively, the teachings in the prior art are useful, but do not address issues such as: the large int inherent with multiple branched horizontal wells, well disposition and configuration within a given rock formation volume for enhanced heat mining or ature maxima and minima along the well length.

Recognizing these shortcomings, the instant technology set forth herein advances geothermal technology one step further and combines inant unit operations in a unique manner to efficiently recover thermal energy within a geothermal gradient regardless of gradient y and variation, formation ty, ambient conditions, geographic location, inter alia.

In the parallel prior art from the oil and gas industry, drilling techniques for multilateral wells, specific drilling fluids, etc. are well established, however simple transference to geothermal exploration and recovery is not realistic or feasible; geothermal energy recovery present its own complications. A number of factors must be considered in order to synthesize a viable recovery protocol. This requires the ability to cally adjust thermodynamic parameters during energy recovery, mitigate any well integrity or performance issues, reverse, reroute or stop working fluid flow, change working fluid ition among others. Unification in the proper sequence es analysis ated on a vast appreciation of a number of technologies; absent this, the solution becomes labyrinthine.

This is evinced in the myriad of geothermal prior art which has struggled with drilling issues, working fluid formulations, complex heat exchanger arrangements with both down hole and surface positioning, gradient quality and location, continuous and discontinuous loops, wellbore casings and variations thereto.

Owing to the landscape of the rmal prior art, a technique which navigates h the noted complications to circumvent them for a universal solution, would be beneficial.

The present ion provides effective ons to the current limitations to the degree that geothermal energy production can economically become a premier energy production method.

DISCLOSURE OF THE lNVENTlON One object of the present invention is to provide control of the temperature profile in rock surrounding geothermal wells.

A further object of one embodiment of the present invention is to provide a method for zing geothermal energy recovery within a formation having a geothermal gradient, comprising: determining the geothermal gradient within the rock volume of said ion; forming a wellbore configuration for location and positioning within said rock volume with the ration of the wellbore based on a determined geothermal gradient for maximum thermal recovery, the wellbore ration comprising a closed loop having an inlet well and outlet well and lateral interconnecting section in fluid communication, said lateral n of said configuration positioned within said rock volume; selecting at least one working fluid for circulation in a predetermined sequence within said configuration based on: wellbore configuration; geothermal gradient ion; and formation geology; determining working fluid temperature from sequenced circulation within said wellbore configuration; and selecting at least one of: working fluid rerouting and distribution within said configuration; working fluid composition; working fluid flow rate within said configuration; working fluid flow direction; and combinations f to maximize energy recovery with said working fluid from said rock volume.

Heat transfer from the rock is inversely proportional to the working fluid temperature within the wellbore. The heat transfer maxima occurs at the “heel” of the inlet well where the temperature of the working fluid within the well is at a minimum. The working fluid heats up as it traverses the horizontal section of the well towards the “toe” of the well. This is evinced by the thermal profile data. The heat transfer profile is observed generally as a tapering from the heel to toe with the minima at the outlet well.

It has been found that various configurations of combined wells have a beneficial effect on the profile, allowing higher heat extraction from a given volume of rock and reducing well construction costs and “dead spots” where heat extraction is inefficient.

Interdigital disposition or meshing of horizontal sections of proximate wells has been found to compensate for temperature maxima and minima in wells. The effect is realized with ity ient for thermal contact between wells. With g fluid flow in tion between proximate wells a temperature equilibrium can be induced in the geothermal formation such that the maxima of one well offsets or mitigates the minima of a proximate well.

To further enhance the extraction of l energy from within the formation the wellbore ration network may be formed by sealing the wellbore during drilling absent casing in lateral sections of res. This obviously has a pronounced cost t together with ageous thermodynamics. This contributes to the universal applicability of the protocol; the configuration can be utilized in any one of a high temperature gradient, low temperature gradient, conductive zone within the gradient, convective zone within the gradient, high permeability zone within the formation, low permeability zone within the formation and combinations thereof.

The sealing composition may also include materials to enhance the thermal conductivity of the seal. Suitable compositions may be seen in the known art typically by Halliburton, Baker Hughes and others. r, the working fluid composition may e ves to maintain wellbore integrity in the configuration and fluid density for compressive th of the wellbores in the configuration.

Ancillary mechanical or chemical unit operations and combinations thereof may be ed to in re integrity. This may comprise use of chemical sealants and densifying agents introduced into the wellbore configuration at predetermined locations in at least one of a single operation and sequentially phased operations, depending on requirements.

In respect of mechanical operations, casing/ multilateral junctions may be incorporated on predetermined locations as required.

Drag reducing agents or other additives may be added to the working fluid to improve thermodynamic performance, reduce or eliminate parasitic pump load, and enable larger wellbore networks to be drilled while maintaining optimum hydraulic performance. 2019/000111 Further, the method facilitates providing sufficient lic frictional pressure losses in each lateral section to passively control flow distribution within lateral sections within said configuration.

In respect of the wellbore configurations, the same may be spaced, angled, stacked, conglomerated, interdigitated and onnected and combinations thereof individual within the rock volume to maximize energy extraction. Orientation will also mitigate any l interference or “dead spots” as well as the potential need for l recharge of individual wellbores that may require inactivity with quiescent working fluid flow for a predetermined time frame.

Inlet wells and outlet wells of the configurations may be common to at least some of the proximate wellbore configurations. Single or multiple sites are also contemplated.

Further to this the closed loops of the wellbore configurations may be above or below the surface site. This will depend on specifics of the individual situation.

Having thus generally described the invention, reference will now be made to the anying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 is a temperature profile illustrating temperature at the radial distance from the wellbore centreline ve to the axial on along the horizontal wellbore; Figure 2 is a thermal illustration of the radial volume of rock mined for heat for a pair of spaced apart horizontal wellbores; Figure 3 is a view similar to Figure 2 where working fluid flow is reversed for a pair of horizontal wellbores; Figure 4 is a schematic illustration of a well system having a plurality of horizontal wells ly connected to an inlet well and an outlet well; Figure 5 is a view similar to Figure 4 rating an interdigitated well system according to one embodiment of the present invention; Figure 6 is a top plan view of an alternate embodiment of the t invention; Figure 7 is a cross section of a well arrangement; Figure 8 is a cross section of another well arrangement; Figure 9 is atop plan view of an alternate ment of the present invention; Figure 10 is a cross section along line 9-9 of Figure 9; Figure 11 is a schematic ration of a wellbore configuration network within a geothermal gradient of a rock formation; Figure 12 is a schematic illustration of a circulation sequence within wellbore systems in a configuration network; Figure 13 is a flow chart of events involved in the protocol; and Figure 14 is a closed—loop wellbore k overlain on a formation temperature distribution map Similar numerals used in the Figures denote similar elements INDUSTRIAL ABILITY The technology has applicability in the geothermal energy ry art.

BEST MODE FOR CARRYING OUT THE INVENTION ing now to Figure 1, shown is a thermal illustration depicting the temperature tapering along the axial position of the horizontal well for a given surrounding rock volume. Noteworthy is the fact that there is a heating of the working fluid from the heel of the well to the toe. Heat transfer from the rock is inversely proportional to this working fluid temperature. Accordingly, most of the heat energy is captured at a maximum of the heel and a minimum of the toe. This obviously has efficiency tions, since maxima and minima are created.

Referring now to Figure 2, shown is a plan view of two spaced apart horizontal wellbores 10 and 12 disposed within a geothermal formation 14. The wells 10 and 12 are spaced apart but remain in l contact. Each wellbore 10 and 12, in this example, has a working fluid flow in the same direction as identified in the Figure. The thermal profile, as discussed with reference to Figure 1 is depicted for each wellbore 1O and 12, with the profiles diverging from one another thus leaving the area 16, a “dead spot” from which no heat energy is extracted in a relevant timeframe.

Figure 3 rates a first solution to the extraction issue raised in respect of Figure 2. In this Figure, flow direction between horizontal wellbores 10 and 12 is reversed as depicted. In this manner, the temperature maxima and minima are equilibrated for each re 10 and 12 and the rock volume between the two wellbores 10 and 12 has no “dead spot” or “unmined” , i.e. area 16. As such, for a given volume of rock within which the wellbores 10 and 12 are oned, a greater radial volume of rock can be mined for heat or in the vernacular, a greater amount of heat can be recovered per unit area. The wellbores are also spaced closer together, providing a significant reduction in well drilling/construction costs.

Figure 4 is a schematic illustration of a prior art multiple lateral or horizontal well system, generally denoted by numeral 18. In this embodiment, horizontal wellbores 20 through 32 are in a generally radial spaced apart relation all g a common inlet wellbore 36 and outlet wellbore 38. In this ment, the horizontal wellbores are, as an example, between 2000m and 8000m in length.

Figure 5 illustrates an interdigitated or meshed arrangement of two well systems 18. It has been found owing to the effectiveness of the ement discussed in t of Figure 3, that disposing the two well systems 18 in spaced apart, thermal contact presents the benefit as outlined regarding Figure 3. The second well system 18 includes horizontal wellbores 38 though 50 and similar to Figure 4 have a common inlet wellbore 52 and common outlet wellbore 54. By this ement, proximate wellbores, for example, 20,38; 22,40; 24,42, etc. each have opposite working fluid flow direction relative to one another and thus achieve the result as noted with respect to Figure 3.

As will be iated, this substantially ses the well density for a given volume of rock within the geothermal ion and therefore the amount of heat energy extracted into the working fluid.

Turning now to Figure 6, shown is an alternate embodiment of the t invention where well s 18 are arranged side by side in an inverted disposition. In this arrangement, first well system 18 includes multiple wellbores 56, 58 and 60 ly connected to inlet welibore 62 and common outlet wellbore 64. From the inlet 62 to the outlet 64, the multiple wellbores 56,58 and 60 converge and thus spacing there between varies from 62 to 64. Working fluid flow direction is from 62 to 64 as indicated. Working in concert with the multiple res 56,58 and 60 is a second set of multiple wellbores 66,68 and 70. The latter share a common inlet 72 and common outlet 74. This arrangement is the same as that for wellbores 56,58 and 60 with the exception that the convergence is opposite to that of the first well system 18,i.e the fluid flow is from 72 to 74. Further multiple wellbore 66 is space from,but thermally proximate multiple wellbore 60. Each of the weii systems 18 is linked at 76 and 78 for fluid exchange there between. As noted, this is an alternate arrangement to mitigate the maxima and minima temperature profile induced in the rock volume.

Figure 7 illustrates a cross section of 7 le wellbores at the convergent point discussed in connection with Figure 6, near the outlet well, where the spacing relationship between the multiple wellbores 82 through 92 is shown to be similar as d by distance “X” with an example distance of 20m to 80m. The wellbores are coming out of the page. Figure 8 illustrates a cross section of 7 multiple wellbores 82 through 92 at the divergent point, near the inlet well, with example spacing “Y” which is equidistant between 80m and 120m.

This arrangement is an alternative to that discussed regarding Figure 5, however, it achieves the same thermal benefit owing to the fluid flow direction and thermal proximity of the multiple wellbores.

With reference to Figure 9, shown is an alternate embodiment of the ement of Figure 6. in this embodiment, interdigital connection is provided. In this example, le wellbores 96,98 and 100 having a common inlet well 100 and common outlet well 102 and diverging from 100 to 102. Multiple res 96,98 and 100 are interdigitated with multiple wellbores 104, 106 and 108. The latter share a common wellbore inlet 110 and common wellbore outlet 112. The well pattern diverges from 112 to 110. Spacing relationships are observed as with the previous embodiments to achieve the thermal capture results. Each of the well systems is linked for fluid ge at 114 and 116.

Figure 10 is a schematic ration in cross section of a system of wells 118, 120 and 122 in similar spaced relation and thermal contact with wells 124,126 and 128.

Working fluid flow for 118, 120 and 122 is opposite to that for wells 124,126 and 128. lntra well spacing is dependent on a number of factors.

Referring now to Figure 11, shown is a tic illustration of a planned wellbore configuration network within a rock formation having a variable geothermal gradient, denoted by numeral 130. As illustrated in the e, the lateral well systems are denoted by numeral 18 as referenced in respect of the earlier described Figures and may subscribe to anyone or combinations of configurations discussed herein usly.

The numerical designation is for clarity only.

In respect of the disposition of the well systems, the same may be spaced, angled, d, conglomerated, interdigitated, interconnected and combinations f within the rock volume to maximize energy extraction. The disposition will be realized once the geothermal gradient is determined, along with the rock thermal conductivity. This flexibility in the methodology is further enhanced by the fact that the drilling of the res can be done while sealing the wellbore absent casing. In some specific scenarios, casing may be used in predetermined locations within the network.

The configuration may include discrete closed loop wellbore configurations having an inlet 36 and outlet 38 and ls 20 through 32 ( shown more clearly in Figure 3 ) disposed within the gradient 130 and/or the same may be interconnected with common tion of inlets 36 and outlets 38 between configurations in a network.

The common inlet connections being indicated by numeral 132 and common outlets by numeral 134. Further, the outlet common 134 Or individual outlets 38 may be networked to adjacent or proximate wellbore configurations referenced by numeral 136. This is denoted by dashed line and numeral 138.

The gradient may comprise a high temperature gradient, low temperature gradient, conductive zone within said gradient, convective zone within said nt, high bility zone within the formation, low permeability zone within the formation and combinations thereof.

Figure 12 schematically depicts the cross exchange of the working fluid within the network. In this manner, thermal variation or under production is d in the k of wells. Accordingly, the working fluid may be rerouted and distributed within the configuration, the working fluid composition changed completely or modified with ves, the fluid flow rate altered, direction altered and combinations thereof to ze energy recovery with the working fluid from the geothermal gradient.

Additionally, g fluid flow may be stopped entirely at a predetermined on within the network depending on performance and/or thermal issues. This procedure also facilitates thermal recharge of a wellbore or system thereof.

Returning to Figure 11, the closed loop wells 18 may be closed above or below the surface, S, as illustrated. This will depend on the ambient conditions and other variables within the purview of one skilled. Operational control, such as fluid supply, temperature monitoring, fluid sampling, direction, rate inter alia can be done on the surface,S, at 140 using any of the suitable mechanisms and instrumentation well known in the art for achieving the results desired. red thermal energy can be transferred to a suitable energy converter 142 for distribution and/or stored in a storage device 144 for deferred use. Advantageously, the recovered energy may be used to generate steam for use in an rial process. Depending on ic conditions, the wellbore network may be set up adjacent or proximate an existing industrial project.

Figure 13 illustrates the overall protocol with the individual phases delineated.

Within phases 2 through 4, the event sequence may vary depending on the ambient conditions, geology, gradient, rock type and variability etc. The intent is to set forth the elegance of the ol with key operations necessary to maximize thermal recovery less of conditions which is a distinguishing e of the present technology.

Figure 14 illustrates how the previous concepts presented are placed in context of a le temperature bution within the target formation, illustrated by the isotherm contours. The optimum re k configuration, spacing among laterals, flow direction, and flow rate varies according to the geothermal gradient and the temperature distribution in the target zone.

Reference will now be made to an example of the protocol.

Generally, the first step in optimizing a closed-loop system is determination of the geothermal temperature gradient in the area. The gradient is lly between 28—35°C/km in sedimentary basins, but can increase up to 50°C in sedimentary basins with a shallow Currie Point depth (thin crust), and in areas with high heat flow can be up to 150°C/km.

Target zones are identified to place the geothermal wellbores. Unlike traditional geothermal technology, for closed-loop systems any rock is an available zone since no permeability, porosity, or rare geological characteristics are required. Target zones can be sandstone, shale, siltstone, mudstone, dolomite, ates, or crystalline basement rock.

Some target zones are preferable due to a combination of temperature distribution, thermal conductivity, and drilling rate of penetration. Therefore, the next step is to use the geothermal gradient to ascertain the temperature distribution of the rock volume as illustrated in Figure 14, which shows a top-down map of the temperature contours (isotherms) of a given formation. Suitable atures can be from 85°C to 250°C or as high as 350°C.

Thermal conductivity distribution within the rock volume is estimated. This can be based on direct ements, extrapolated laboratory data, or calculated from ct data such as sonic velocity, logy, or rock type. Thermal conductivity ranges from 1.7 W/m K for soft shales to r than 4 W/m K for quartz rich sandstones.

The next step is to determine the unconfined compressive strength (UCS) of the target zones and then estimate drilling rate of penetration which is a strong function of Unconfined Compressive Strength.

Traditional rmal technology involves ing for a hydrothermal zone and then optimizing the planning and development of the resource. In contrast, since any geological formation is suitable for closed—loop systems, the target zone selection can be partly based on the optimum drilling rate of penetration. UCS governs rate of penetration and typically ranges from 40 MPa for weak shales to as high as 300 MPa for crystalline basement rocks. The rate of penetration while drilling is generally 5 m/hr for hard rock to over 300 m/hr for soft rock.

All mechanical and chemical unit operations are considered for ining wellbore integrity of a -loop system. The rock type and unconfined compressive strength will largely dictate the optimum solution. One ines if a sealant and or working fluid additives is sufficient, or if casing and or mechanical junctions are required, or any combination of these.

With the face design inputs largely identified, the next step is to e the ature-dependent energy profile required by the end-user. This can be a profile of thermal , cooling power, or electrical power, or a combination. Typically, the profile varies throughout the day and throughout the seasons. Likewise, the ambient conditions of the surface site and time-based g can vary throughout the day and season and optionally can be analysed.

The wellbore network configuration in three dimensions is designed to maximize useful energy extraction from the rock volume. Part of this design involves determining the ve spacing between wellbores in the k to minimize thermal interference and “dead spots", or areas of the rock volume where energy is not efficiently extracted.

The optimum spacing is a function of temperature distribution in the target zone, thermal conductivity, and working fluid characteristics and flow rate. ng costs must also be considered. Spacing is typically from between 20m and 120m between wellbores.

Spacing between adjacent wellbores in the network can vary along the length of the wellbores to maximize performance, minimize interference, and minimize “dead spots”.

The wellbore network configuration is also designed to e sufficient hydraulic frictional pressure losses in each lateral to passively control flow distribution among the various laterals within the configuration.

Surface equipment should be integrated into the system design, as the outlet from the surface infrastructure is simply the input into the subsurface closed—loop system. ore surface facility equipment design and mance has an impact on subsurface design and mance and vice-versa. As an example, a heat engine with an outlet temperature of 70°C will have a different optimum subsurface wellbore network design than when d to a heat engine with an outlet temperature of 90°C.

The working fluid composition within the wellbore network is determined along with the optimum flow rate over time. The working fluid composition is selected for optimum thermodynamic performance as well as to in wellbore integrity. The working fluid may be water, supercritical fluids, hydrocarbons, erants, or any other fluid. Wellbore ity additives can consist of sealants, reactants, solid particulates, bridging agents, lost ation al, densifying agents to maintain sufficient compressive th on the wellbore, or any combination. Drag reducing agents may be added to the working fluid to enable a larger wellbore network configuration without reaching hydraulic limits or impacting overall thermodynamic efficiency.

The working fluid is circulated in the k. Flow rate is typically from between 40 US and 200 US water equivalent through a network of wellbores in series. 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 correspondingly.

Thermal energy is recovered from the working fluid circulating through the closed-loop wellbore network. Optionally, flow can be re-distributed within the network to maximize performance. 2019/000111 The red energy is distributed, stored, and or converted to electricity. The conversion between various forms of energy and storage may be determined by end— user requirements and/or c pricing.

During operations, one monitors the fluid temperature and compositional anomalies, optionally monitors and/or estimates thermal profiles of res in the network, and optionally monitors and or tes wellbore integrity of wellbores in the network.

Based on real time monitoring and estimates, operations may be implemented to optimize thermodynamic performance. As examples, these include changes in flow rate, flow direction, and flow distribution among wellbores in the network. For instance, the outlet fluid temperature in one part of the k may be higher than expected, while fluid temperature in another part of the network may be low; flow rates can be adjusted accordingly.

Wellbore integrity can be red via measured re drops across the wellbore network, measured working fluid volume balance (leak-off or addition of volume), compositional variations, and produced solids volume and characteristics.

Dynamic repair of wellbores can be initiated, such as with working fluid additives, reactants, or by circulating fluid slugs containing sealants, bridging agents, or lost circulation material.

It will be appreciated that the unit operations described above can be performed in , or in parallel in an integrated iterative process, or a combination.

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Claims (24)

CLAIM :

1. A method for maximizing geothermal energy recovery within a formation having a rmal gradient, comprising: determining the geothermal nt within the rock volume of said formation; forming a wellbore configuration for location and positioning within said rock volume with the configuration of the wellbore based on a determined geothermal gradient for maximum thermal recovery, the wellbore configuration comprising a closed loop having an inlet well and outlet well and lateral interconnecting section in fluid communication, said lateral section of said configuration formed directly in said rock volume; said wellbore uration being formed by sealing the wellbore during drilling without utilizing casing in said lateral section of said wellbore in formation and operation; selecting at least one working fluid for circulation in a predetermined sequence within said configuration based on: wellbore configuration; geothermal gradient variation; and formation geology; ining any g fluid temperature differences at ent points in said configuration from sequenced circulation within said wellbore configuration; and ing at least one of: working fluid rerouting and distribution within said configuration; working fluid composition; working fluid flow rate within said configuration; working fluid flow direction; and combinations thereof to maximize energy recovery with said working fluid from said rock volume.

2. The method as set forth in claim 1 wherein determination of said gradient includes determining temperature distribution within said rock volume.

3. The method as set forth in claim 1 or 2, r including the step of characterizing rock type and thermal conductivity within said rock volume.

4. The method as set forth in in any one of claims 1 h 3, wherein selection of working fluid ition includes incorporating additives to maintain wellbore integrity in said configuration and fluid density for ssive th of said wellbore configuration.

5. The method as set forth in in any one of claims 1 through 4, further including the step of controlling at least one of working fluid ature, wellbore integrity in said configuration, and thermal recharge of a wellbore in said configuration during operation.

6. The method as set forth in any one of claims 1 through 6, further including the step of introducing ancillary mechanical or chemical unit operations and combinations thereof to maintain wellbore integrity.

7. The method as set forth in claim 6, n said ancillary mechanical operations include introducing casing and multilateral junctions into said wellbore configuration at predetermined ons.

8. The method as set forth in claim 7, wherein said ancillary chemical operations include introducing at least one of chemical sealant, densifying agents and bridging agents into said wellbore configuration at predetermined ons in at least one of a single operation and sequentially phased operations.

9. The method as set forth in any one of claims 1 through 8, further including at least one of spacing, angling, ng, conglomerating, interdigitating and interconnecting and combinations thereof individual res in said configuration within said rock volume to maximize energy extraction.

10. The method as set forth in claim 9, further including the step of selectively connecting inlet wells and outlet wells at predetermined locations in said configuration at one or more superterranean locations.

11. The method as set forth in any one of claims 1 through 10, wherein the step of forming a re configuration comprises forming a network of wellbores within said rock volume of said formation which ally have a common inlet well and a common outlet well connected to the wellbores at a superterranean location.

12. The method as set forth in any one of claims 1 through 11, wherein sequenced circulation includes flow rate variation, flow direction, quiescence and combinations thereof.

13. The method as set forth in any one of claims 1 through 12, r including the step of ng said working fluid in predetermined locations within said wellbore configuration to determine compositional variations relative to uncirculated working fluid.

14. The method as set forth in claim 13, further including the step of determining if said itional variations are related to chemical or mechanical wellbore factors.

15. The method as set forth in any one of claims 1 h 14, further including the step of controlling the thermal profile variation between proximate wellbores in said configuration, said controlling including: selecting said wellbore configuration within said rock volume based on temperature bution within said rock volume; spacing wellbores of said configuration to reduce thermal interference and inefficient thermal recovery between proximate wellbores.

16. The method as set forth in claim 15, further including the step of: introducing a first working fluid into a first well of said wellbores to absorb thermal energy from surrounding formation rock in said gradient from a maximum to a minimum through said well; introducing a second working fluid into a second well of said res to absorb thermal energy from surrounding formation rock in said ion from a maximum to a minimum through said well, first fluid flow being in an opposite direction to said second fluid flow to induce thermal consistency within the rock volume proximate said wells absent thermal minima and maxima.

17. The method as set forth in any one of claims 1 through 16, further including integrating a surface ement with said loop to utilize red thermal .

18. The method as set forth in claim 17, n said surface arrangement comprises at least one of a steam generating arrangement for use in industrial operation, a power generating arrangement, a power storage arrangement, a distribution network for ive distribution of energy to linked wellbore configurations and combinations thereof.

19. The method as set forth in any one of claims 1 through 18, further including the step of introducing a drag ng agent to said working fluid to enable an expanded wellbore network uration while maintaining m hydraulic performance.

20. The method as set forth in any one of claims 1 through claim 19, further including the step of providing sufficient hydraulic frictional pressure losses in each lateral to ely control flow distribution within lateral sections within said configuration.

21. The method as set forth in any one of claims 1 through 20, further including the step of determining interaction between thermal conductivity and drilling rate-of-penetration for positioning and location of said wellbore within said rock volume.

22. A method for maximizing geothermal energy recovery within a formation having a geothermal gradient, comprising: determining the geothermal gradient within a rock volume of said formation; forming a wellbore configuration for location and positioning within said rock volume with the configuration of the wellbore based on a determined geothermal gradient for maximum thermal recovery, the wellbore configuration comprising a closed loop having an inlet well and outlet well and lateral interconnecting section in fluid communication, said l section of said configuration formed directly in said rock volume and sealed during drilling without utilizing casing in said lateral interconnecting section of said wellbore in formation and operation; selecting at least one working fluid for circulation in a predetermined sequence within said configuration based on: wellbore configuration; geothermal gradient variation within said rock volume of said ion; and the geology of said formation; determining any working fluid temperature differences at different points in said configuration from sequenced ation within said wellbore configuration; and selecting at least one of: working fluid rerouting and distribution within said configuration; working fluid composition; g fluid flow rate within said configuration; working fluid flow direction; controlling the thermal profile variation between proximate wellbores in said configuration, said controlling ing: ing said wellbore configuration within said rock volume based on ature distribution within said rock volume; spacing wellbores of said configuration to reduce thermal erence and inefficient thermal recovery between proximate wellbores; and combinations thereof to maximize energy ry with said working fluid from the variable rmal gradient within said rock volume.

23. A method for maximizing geothermal energy recovery within a formation having a rmal gradient, comprising: determining the geothermal gradient within a rock volume of said formation; forming a wellbore configuration for location and positioning within said rock volume with the configuration of the wellbore based on a determined geothermal gradient for maximum thermal recovery, the wellbore configuration sing a closed loop having an inlet well and outlet well and lateral interconnecting section in fluid communication, said lateral section of said configuration formed directly in said rock volume, said wellbore uration being formed by sealing the wellbore during drilling without utilizing casing in said lateral interconnecting section of said wellbore in formation and operation; selecting at least one g fluid for circulation in a predetermined sequence within said uration based on: wellbore configuration; geothermal gradient variation within said rock volume of said formation; and the geology of said formation; determining any working fluid temperature ences at different points in said configuration from sequenced circulation within said wellbore configuration; and selecting at least one of: working fluid rerouting and distribution within said configuration; working fluid composition; working fluid flow rate within said configuration; working fluid flow ion; introducing ancillary mechanical or chemical unit operations and combinations f to maintain re integrity; and combinations thereof to maximize energy recovery with said working fluid from the variable geothermal gradient within said rock volume.

24. A method for maximizing geothermal energy ry within a formation having a rmal gradient, comprising: determining the geothermal gradient within a rock volume of said formation; forming a wellbore configuration for location and positioning within said rock volume with the configuration of said wellbore based on a determined geothermal gradient for maximum thermal recovery, the wellbore configuration comprising a closed loop having an inlet well and outlet well and lateral interconnecting n in fluid communication, said wellbore configuration being formed by sealing the wellbore during drilling without utilizing casing in said lateral onnecting section of said wellbore in formation and operation; controlling the thermal e variation n proximate wellbores in said configuration, said controlling including: selecting said wellbore configuration within said rock volume based on temperature distribution within said rock volume; spacing wellbores of said configuration to reduce thermal interference and inefficient thermal recovery between proximate wellbores; introducing a first working fluid into a first well of said wellbores to absorb thermal energy from nding formation rock in said gradient from a maximum to a minimum through said well; introducing a second working fluid into a second well of said wellbores to absorb thermal energy from surrounding ion rock in said formation from a maximum to a minimum h said well, first fluid flow being in an opposite direction to said second fluid flow to induce thermal consistency within the rock volume proximate said wells absent thermal minima and maxima.