Systems and processes for harvesting heat from subterranean geologic formations

Abstract

Systems and processes for harvesting heat from subterranean geologic formations, and especially in dry hot rock formations, using sequential harvesting of stacked or partially stacked reservoirs. Producing electrical power using same.

Description

SYSTEMS AND PROCESSES FOR HARVESTING HEAT FROM SUBTERRANEAN GEOLOGIC FORMATIONSCross-Reference to Related ApplicationsThis application is entitled to and claims priority to United States provisional application No. 63680402, filed August 7, 2024, which earlier filed provisional application is incorporated by reference herein in its entirety.

[0001] BACKGROUND INFORMATION

[0002] Technical Field

[0003] The present disclosure relates to systems and processes for harvesting heat from subterranean geologic formations, and more particularly to systems and processes for harvesting heat from subterranean geologic formations between injector and producer wells in enhanced geothermal systems.

[0004] Background Art

[0005] A naturally occurring geothermal system, known as a hydrothermal system, is defined by three key elements: heat, fluid, and permeability at depth. An Enhanced Geothermal System (EGS) is a man-made reservoir, created where there is hot rock but insufficient or little natural permeability or fluid saturation. In an EGS, fluid is injected into the subsurface under carefully controlled conditions, which cause pre-existing fractures to re-open, creating permeability. What is an Enhanced Geothermal System (EGS)? U. S. Dept, of Energy, DOE / EE-0785, September 2012. A different approach, closed-loop geothermal systems (CLGS), overcomes permeability issues by circulating a working fluid through a sealed downhole heat exchanger to absorb and transport heat.CLGS is a versatile technology that can be implemented in a wide variety of different well pipe configurations using a choice of working fluids (such as water and sCO2) to optimize site specific costs and performance. Muir, New Opportunities and Applications for Closed-Loop Geothermal Energy Systems, Geothermal Rising Bulletin, December 2020, Vol. 49, No. 4.

[0006] Extraction of heat from Dry Hot Rock (DHR) presents several efficiency and power advantages over other EGS or CLGS approaches for geothermal energy recovery. Heat is harvested from DRH via an Enhanced Rock Volume (ERV) built from a horizontal injector, horizontal producer, and a series of fractures connecting the injector to the producer. Heat is recovered effectively only from the ERV due to the low thermal conductivity of the rock. Long horizontal well laterals can harvest heat from a large area that is dependent on the effective area of the fractures, but the depth of recovery from the area is limited by the rock thermal conductivity. The quality of heat will diminish as this ERV is harvested. Heat in rock outside this volume is not recovered and remains to be recovered. Heat is harvested from the ERV faster than the natural geothermal gradient will replenish the heat in the volume. In fact, it can take tens to hundreds of years to replenish the heat. This means that once the heat quality harvested becomes uneconomic, the ERV should be abandoned. However, abandoning the wells because the ERV is depleted can be costly. It is beneficial to reuse the wells.

[0007] Heat outside the abandoned ERV remains unharvested. There is heat potential vertically above and below the harvested volume that can be reached by the existing wells. As may be seen, current practices may not be adequate for all circumstances, and do not address the noted problems with respect to extracting heat from DHR. There remains a need for more robust systems and processes for harvesting heat fromsubterranean geologic formations, and in particular geothermal formations. The systems and processes of the present disclosure are directed to these needs.

[0008] SUMMARY

[0009] In accordance with the present disclosure, systems and processes are described which reduce or overcome many of the faults of previously known systems and processes. In systems and processes of the present disclosure laterals are drilled from an existing well used by the depleted ERV, either above or below, (or both above and below) the abandoned ERV to create a new ERV. These “stacked ERV’ s” of the present disclosure are applicable to enhanced geothermal systems since an ERV is required to harvest the heat. Since the rock has no effective permeability, there can be no conventional fluid flow within the rock. Heat is recovered from the rock only by thermal conduction within the rock. The “new” (second, third, N) ERV’s are reached by drilling and completing new laterals, which will be cooler above and hotter below a first (sometimes referred to as the abandoned) ERV. The systems and processes of the present disclosure can be applied in vertical, deviated and horizontal wells, regardless of temperature of the formation and regardless of the completion of the well but arc particularly well-suited for horizontal wells.

[0010] A first aspect of the disclosure are systems for harvesting heat from subterranean geologic formations comprising (or consisting essentially of, or consisting of): a) an injector well extending from a surface to a subterranean geologic formation, the injector well paired with one or more production wells and configured to form a first enhanced rock volume (FERV), the injector well having a first perforated injector horizontal lateral, and the one or more production wells having a firstperforated production horizontal lateral above the first perforated injector horizontal lateral; b) an injection pump configured to pump a first heat extraction fluid at a first temperature (Tl), a first pressure (Pl), and at a first rate (Rl) into the injector well and through the first perforated injector horizontal lateral and its perforations, the first heat extraction fluid configured to contact the FERV and transfer heat from the FERV to the first heat extraction fluid to form a heated first heat extraction fluid at a second temperature (T2), the first pressure (Pl) sufficient to force the heated first heat extraction fluid through the first perforated production horizontal lateral and the one or more production wells; c) a completion sub-system configured to seal the injector well either above or below the FERV after formation of the FERV and harvesting heat from the FERV ; d) the injector well having a second perforated injector horizontal lateral, and the one or more production wells having a second perforated production horizontal lateral above the second perforated injector horizontal lateral, the completion subsystem, second perforated injector horizontal lateral, and the second perforated production horizontal lateral defining a second enhanced rock volume (SERV); c) the injection pump configured to pump a second heat extraction fluid at a third temperature (T3), a second pressure (P2), and at a second rate (R2) into the injector well and through the second perforated injector horizontal lateral and its perforations, the second heat extraction fluid configured to contact the SERV and transfer heat from the SERV to the second heat extraction fluid to form a heated second heat extraction fluid at a fourth temperature (T4), the second pressure (P2) sufficient to force the heated second heat extraction fluid through the second perforated production horizontal lateral and the one or more production wells.

[0011] A second aspect of the disclosure are processes for harvesting heat from subterranean geologic formations, comprising (or consisting essentially of, or consisting of): a) completing an injector well paired with one or more production wells for forming a first enhanced rock volume (FERV), the injector well having a first perforated injector horizontal lateral, and the one or more production wells having a first perforated production horizontal lateral above the first perforated injector horizontal lateral; b) harvesting heat from the FERV by pumping a first heat extraction fluid at a first temperature (Tl), a first pressure (Pl), and at a first rate (Rl) into the injector well and through the first perforated injector horizontal lateral and its perforations, the first heat extraction fluid contacting the FERV, transferring heat from the FERV to the first heat extraction fluid to form a heated first heat extraction fluid at a second temperature (T2), the first pressure (Pl) sufficient to force the heated first heat extraction fluid through the first perforated production horizontal lateral and the one or more production wells; c) moving up or down hole in the injector well and building a second enhanced rock volume (SERV) by completing the injector well a second time paired with the one or more production wells for forming a second enhanced rock volume (SERV), the injector well having a second perforated injector horizontal lateral, and the one or more production wells having a second perforated production horizontal lateral above the second perforated injector horizontal lateral; d) harvesting heat from the SERV by pumping a second heat extraction fluid at a third temperature (T3), a second pressure (P2), and at a second rate (R2) into the injector well and through the second perforated injector horizontal lateral and its perforations, the second heat extraction fluid contacting the SERV, transferring heat from the SERV to the second heat extraction fluid to form a heated second heatextraction fluid at a fourth temperature (T4), the second pressure (P2) sufficient to force the heated second heat extraction fluid through the second perforated production horizontal lateral and the one or more production wells; and e) repeating steps (c) and (d) at least once.

[0012] Certain system and process embodiments of the present disclosure may comprise wherein the subterranean geologic formation is a subterranean geothermal formation, and the injector well and production well are in dry hot rock (DHR). In certain systems and processes of the present disclosure the injector well may be cemented. In yet other systems and processes the injector well may be uncemented.

[0013] Certain system and process embodiments of the present disclosure may comprise wherein the production well is selected from an open hole, a well comprising a cemented or an uncemented liner, and a well selectively segmented by ECP and sliding sleeves or pre-perforated liner.

[0014] Certain system and process embodiments of the present disclosure may comprise: a) temperature measuring devices for measuring Tl, T2, T3, and T4; b) flow rate measuring devices for measuring R1 and R2; c) pressure measurement devices for measuring Pl and P2; wherein the injection pump is capable to produce R1 and Pl of the first heat extraction fluid capable of transferring at least about 760 GJ / hr. (gigajoules / hr.) of heat from the subterranean geologic formation to the first heat extraction fluid.

[0015] Certain system and process embodiments of the present disclosure may comprise:a) temperature measuring devices for measuring Tl, T2, T3, and T4; b) flow rate measuring devices for measuring R1 and R2; c) pressure measurement devices for measuring Pl and P2; wherein the extraction pump is capable to produce R2 and P2 of the second heat extraction fluid capable of transferring at least about 730 GJ / hr. of heat from the subterranean geologic formation to the second heat extraction fluid.

[0016] Certain system and process embodiments of the present disclosure may comprise wherein the injection pump is one or more surface pumps.

[0017] In certain systems and processes of the present disclosure the first and second heat extraction fluids are independently selected from water, brine, viscosified fluids, energizing fluids, and polymer based fluids. The first and second heat extraction fluids may or may not be the same.

[0018] In certain systems and processes of the present disclosure the injector well may be configured to utilize single-path injection through either an inner conduit or through an annulus between the inner conduit and casing, wherein the inner tubing is selected from in place tubing, drill pipe, and coiled tubing.

[0019] In certain systems and processes of the present disclosure the injector well may be configured to utilize dual injection paths comprising a first injection path through an inner conduit and a second injection path through an annulus between the inner conduit and casing, and wherein the injection pump comprises a first injection pump for the first injection path and a second injection pump for the second injection path. In certain systems and processes of the present disclosure the first injection pump may be configured to pump the first heat extraction fluid through the first injection path, andthe second injection pump may be configured to pump the second heat extraction fluid through the second injection path, wherein the first and second heat extraction fluids are different in one or more physical and / or chemical properties.

[0020] Certain system and process embodiments may comprise wherein the injection pump comprises one or more surface pumps. Yet other systems may comprise one or more surface pumps for a first injection path, and one or more other surface pumps for a second injection path, especially in embodiments where dual injection paths (inner conduit and annulus) are used.

[0021] Certain system and process embodiments may comprise wherein the one or more heat extraction fluids comprises a propping agent such as sand, bauxite, petroleum coke, and the like, with or without other materials, such as bridging agents.

[0022] In certain embodiments the systems and processes of the present disclosure may comprise one or more components selected from the group consisting of one or more pressure control devices, (also referred to as chokes), one or more flow measurement devices, one or more accessory equipment, and combinations thereof. In certain embodiments the one or more accessory equipment may be selected from the group consisting of one or more connectors, one or more isolation valves, and one or more pressure relief valves. In certain embodiments the one or more components may comprise one or more redundant components in the system. Certain system embodiments may comprise one or more quick connect / quick disconnect connectors.

[0023] In certain embodiments one or more logic devices may be provided to control all or portions of the systems and processes of the present disclosure, and the logic device may be configured to be operated and / or viewed from a Human / MachineInterface (HMI) wired or wirelessly connected to the logic device. Certain embodiments may include one or more audio and / or visual warning devices configured to receive communications from the logic device upon the occurrence of a pressure rise (or fall) in a sensed pressure above (or below) a set point pressure, or a change in concentration of one or more sensed concentrations or temperatures, or both, above one or more set points. The occurrence of a change in other measured parameters outside the intended ranges may also be alarmed in certain embodiments. Other measured parameters may include, but are not limited to, liquid or gas flow rate, and liquid density.

[0024] Certain system and process embodiments of this disclosure may operate in modes selected from the group consisting of automatic continuous mode, automatic periodic mode, and manual mode. In certain embodiments the one or more operational equipment may be selected from the group consisting of pneumatic, electric, fuel, hydraulic, and combinations thereof.

[0025] In certain embodiments, pressure (P), temperature (T), density, and / or mass flow may be sensed inside the injector and / or producer well tubing, the annulus, the subterranean geologic formation, or any combination of these. Mass flow sensors may be employed. All combinations of sensing T, P, density, and / or mass flow in the injector and / or producer tubing or inner pipe, in the annulus, and / or in the formation are disclosed herein and considered within the present disclosure.

[0026] As used herein “completion sub-system” means a structure or structures for sealing or allowing fluid flow in a controlled manner in desired locations in the subterranean geologic formations, including into and out of injector wells, laterals, ERVs, and producer wells. In certain embodiments of the present disclosure the completion sub-system may include one or more inflatable packers, blowoutpreventers, plugs, downhole tools, and the like. As used herein “power generation subsystem” means a structure or structures for producing electrical power, which may include, but are not limited to, knock-out drums, heat exchangers, pumps, compressors, turbine generators, electrical conduits, and liquid and vapor conduits fluidly and mechanically connected as described herein. Certain embodiments of the present disclosure may include connectivity and / or permeability measurement components and associated components, for example, but not limited to pressure control devices (backpressure valves), pressure relief devices (valves or explosion discs), pipes, conduits, vessels, towers, tanks, mass flow meters, temperature and pressure indicators, heat exchangers, pumps, compressors, and quick connect / quick disconnect (QC / QD) features for connecting and disconnecting choke umbilicals, kill umbilicals, and the like.

[0027] These and other features of the systems and processes of the present disclosure will become more apparent upon review of the brief description of the drawings, the detailed description, and the claims that follow. It should be understood that wherever the term “comprising” is used herein, other embodiments where the term “comprising” is substituted with “consisting essentially of’ arc explicitly disclosed herein. It should be further understood that wherever the term “comprising” is used herein, other embodiments where the term “comprising” is substituted with “consisting of” are explicitly disclosed herein. Moreover, the use of negative limitations is specifically contemplated; for example, certain producer wells may be devoid of casing; certain injector wells may be devoid of dual injection paths; certain systems may be devoid of more than one pump; certain fluids may be devoid of oils and / or other hydrocarbons, and / or devoid of carcinogenic compounds; certain proppants may be devoid of other materials.

[0028] BRIEF DESCRIPTION OF THE DRAWINGS

[0029] The manner in which the objectives of this disclosure and other desirable characteristics can be obtained is explained in the following description and attached drawings in which:

[0030] FIG. 1 is a schematic illustration view of a subterranean geologic formation enhanced rock volume (ERV), an injector well, and a production well in accordance with one embodiment of the present disclosure;

[0031] FIG. 2 is a schematic illustration view of the system of FIG. 1 after completing the injector and production wells a second time for forming a second enhanced rock volume (SERV), where the ERV in FIG. 1 is the first enhanced rock volume (FERV);

[0032] FIGS. 3 A and 3B are schematic process flow diagrams of one embodiment of a surface power generation sub-system and process for generating electricity from heat harvested using systems and processes of the present disclosure; and

[0033] FIG. 4 is logic diagram illustrating one process in accordance with the present disclosure.

[0034] It is to be noted, however, that the appended drawings are not to scale, and illustrate only typical system, process, and sub-system embodiments of the presentdisclosure. Therefore, the drawing figures are not to be considered limiting in scope, for the disclosure may admit to other equally effective embodiments. Identical reference numerals are used throughout the several views for like or similar elements.

[0035] DETAILED DESCRIPTION

[0036] In the following description, numerous details are set forth to provide an understanding of the disclosed systems, combinations, and processes. However, it will be understood by those skilled in the art that the systems and processes disclosed herein may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. All technical articles, published and non-published patent applications, standards, patents, statutes and regulations referenced herein are hereby explicitly incorporated herein by reference, irrespective of the page, paragraph, or section in which they are referenced. Where a range of values describes a parameter, all sub-ranges, point values and endpoints within that range or defining a range arc explicitly disclosed herein. All percentages herein are by weight unless otherwise noted. In the event definitions of terms in the referenced patents and applications conflict with how those terms arc defined in the present application, the definitions for those terms that are provided in the present application shall be deemed controlling. Where a range of values describes a parameter, all sub-ranges, point values and endpoints within that range are explicitly disclosed herein. This document follows the well-established principle that the words “a” and “an” mean “one or more” unless we evince a clear intent to limit “a” or “an” to “one.” For example, when we state “a pump configured to produce an artificial stress barrier by”, we mean that the specification supports a legal construction of “a pump” that encompasses structure distributed among multiple physical structures, and a legal construction of “a well” that encompasses structure distributed among multiple physical structures.

[0037] As mentioned herein, extraction of heat from Dry Hot Rock (DHR) presents several efficiency and power advantages over other EGS or CLGS approaches for geothermal energy recovery. Heat is harvested from DRH via an Enhanced Rock Volume (ERV) built from a horizontal injector, horizontal producer, and a series of fractures connecting the injector to the producer. Heat is recovered effectively only from the ERV due to the low thermal conductivity of the rock. Long horizontal well laterals can harvest heat from a large area that is dependent on the effective area of the fractures, but the depth of recovery from the area is limited by the rock thermal conductivity. The quality of heat will diminish as this ERV is harvested. Heat in rock outside this volume is not recovered and remains to be recovered. Heat is harvested from the ERV faster than the natural geothermal gradient will replenish the heat in the volume. In fact, it can take tens to hundreds of years to replenish the heat. This means that once the heat quality harvested becomes uneconomic, the ERV should be abandoned. However, abandoning the wells because the ERV is depleted can be costly. It is beneficial to reuse the wells.

[0038] Heat outside the abandoned ERV remains unharvested. There is heat potential vertically above and below the harvested volume that can be reached by the existing wells. To address these problems, geothermal projects have started to use stimulation techniques that have shown successes in the O&G (oil and gas) industry to stimulate hydrocarbon-bearing formations, such as use of slickwater fracs, crosslinked fluids, limited entry, and completion designs using devices such as sleeves. These technologies have started to become prevalent in geothermal wells but do not address the fact that heat outside an abandoned ERV remains unharvested. As may be seen, current practices may not be adequate for all circumstances, and do not address the noted problems with respect to extracting heat from DHR. There remains a need formore robust systems and processes for harvesting heat from subterranean geologic formations, and in particular geothermal formations. The systems and processes of the present disclosure are directed to these needs.

[0039] As described in more detail herein with reference to the various drawing figures, systems and processes of the present disclosure address problems identified by the inventors herein, namely the lack of heat harvesting techniques in subterranean geologic formations, in particular in geothermal formations where there remains heat to be harvested outside an abandoned ERV. The inventors herein investigated and developed solutions to these problems.

[0040] Turning now to the drawing figures, FIG. 1 is a schematic perspective illustration view of one system and process embodiment 100 in accordance with the present invention, illustrating schematically a subterranean geologic formation 2 with an ERV, a vertical injector well 4, and a vertical production well 14. An injection pump 1 on the surface “S” receives feed heat extraction fluid (sometimes referred to herein as “extraction fluid” or simply “fluid”) via a conduit 170, pump 1 feeding the extraction fluid via an extraction fluid injection conduit 3 into injector well 4, through a vertical or deviated section 6 and a first perforated injector horizontal lateral 8 into subterranean geologic formation 2. Horizontal lateral has been previously perforated, with a plurality of perforations indicated at 10. A plurality of fluid plumes of extraction fluid 12 flowing out of the plurality of perforations 10 in subterranean geologic formation 2 are indicated in FIG. 1, as are natural seams or cracks 15 in subterranean geologic formation 2.

[0041] Still referring to FIG. 1, a first perforated production horizontal lateral 16 having a plurality of perforations 18 is fluidly and mechanically connected to a vertical and / or deviated section 17 of production well 14. Injector well 4 includes, in embodiment 100,casing 28 which is cemented at 30. Production well 14 includes, in embodiment 100, casing 32 which is cemented at 34. Embodiment 100 further features a conduit 102 routing wanned extraction fluid to a surface power generation sub-system as further explained with reference to FIGS. 3 A and 3B. A conduit 190 routes cooled, collected heat extraction fluid and feeds an extraction fluid extraction pump 162, which through conduits 192, 146, and 114 and 170 returns extraction fluid to injection fluid injection pump 1.

[0042] Arrows 20, 22, 24, and 26 in FIG. 1 indicate direction of flow of extraction fluid in embodiment 100:

[0043] arrow 20 indicates flow direction of cool extraction fluid in injector well 4 and vertical section 6;

[0044] arrow 22 indicates flow direction of cool extraction fluid in first perforated injector horizontal lateral 8;

[0045] arrow 24 indicates flow direction of warm extraction fluid in first perforated production horizontal lateral 16; and

[0046] arrow 26 indicates flow direction of warm extraction fluid in production well vertical section 17 and production well 14.

[0047] Referring now to FIG. 2, in order to harvest heat from a second ERV (“SERV”) located outside of the first ERV (“FERV”), embodiment 100 further features an inflatable packer, BOP, or other completion sub-system component 40 in injector well 4, and inflatable packer, BOP, or other completion sub-system component 54 in production well 14, A second perforated injector horizontal lateral 42, having plurality of perforations 48, is fluidly and mechanically connected to injector well 4 at position 52 in injector well 4, while a second perforated production horizontal lateral 62, having a plurality of perforations 64, is fluidly and mechanically connected to production well14 at location 56 in production well 14. A plurality of fluid plumes of extraction fluid 50 flowing out of the plurality of perforations 64 in subterranean geologic formation 2 are indicated in FIG. 2, as are natural seams or cracks 215 in subterranean geologic formation 2.

[0048] Similar to arrows 20, 22, 24, and 26 in FIG. 1 indicating direction of flow of extraction fluid in the FERV, arrows 44, 46, 58, and 60 in FIG. 2 indicate direction of flow of extraction fluid in the SERV of embodiment 100:

[0049] arrow 44 indicates flow direction of cool extraction fluid in injector well 4;

[0050] arrow 46 indicates flow direction of cool extraction fluid in second perforated injector horizontal lateral 42;

[0051] arrow 58 indicates flow direction of warm extraction fluid in second perforated production horizontal lateral 62; and

[0052] arrow 60 indicates flow direction of warm extraction fluid in production well 14.

[0053] FIGS. 3A and 3B illustrate schematically a process flow diagram of one embodiment 200 of a surface power generation sub-system of systems and processes of the present disclosure. Embodiment 200 includes a first knock-out drum 101, as second knock-out drum 103, and a third knock-out drum 105. (The term “knock-out” is commonly abbreviated as “KO”.) KO drum 101 receives a combined wellhead flow from production well(s) 14 via conduit 102 and produces an extraction fluid vapor stream through a conduit 104 from first KO drum 101, which fluidly and mechanically connects first KO drum 101 to a primary heat exchanger 107, and a liquid extraction fluid stream through conduit 106 from first KO drum 101, which fluidly and mechanically connects first KO drum 101 to second KO drum 103. Second KO drum103 produces a second extraction fluid vapor stream through a conduit 108, which fluidly and mechanically connects second KO drum 103 to a first extraction fluid vapor collection chamber 115, and a second liquid extraction fluid stream through conduit 110, which fluidly and mechanically connects second KO drum 103 to third KO drum 105. Similarly, third KO drum 105 produces a third extraction fluid vapor stream through a conduit 112, which fluidly and mechanically connects third KO drum 105 to a second extraction fluid vapor collection chamber 117, and a third liquid extraction fluid stream through conduit 114, which fluidly and mechanically connects third KO drum 105 to an extraction fluid liquid collection chamber 119 (FIG. 3B).

[0054] Referring still to FIGS 3A and 3B, a cool collected vapor conduit 116 fluidly and mechanically connects second extraction fluid vapor collection chamber 117 with a tertiary heat exchanger 111, and conduit 118 fluidly and mechanically connects tertiary heat exchanger I l l a first turbine generator 152, which produces electricity 150 (dashed line). Conduit 120 fluidly and mechanically connects first turbine generator 152 with a warm collected extraction fluid vapor condenser 121.

[0055] Still referring to FIGS 3 A and 3B, conduit 122 routes extraction fluid vapor heated by primary heat exchanger 107 to a third turbine generator 160 that produces electricity 158 (dashed line). Conduit 124 routes reduced pressure and temperature extraction fluid vapor to first extraction fluid vapor collection chamber 115, which in turn routes a combined extraction fluid vapor to a secondary heat exchanger 109 via a conduit 126, while conduit 128 routes heated extraction fluid vapor to a second turbine generator 156, producing electricity 154 (dashed line). Conduit 130 routes reduced pressure and temperature vapor stream from second turbine generator 156 to second extraction fluid vapor collection chamber 117. Electricity flowing in power lines 150,154, and 158 is gathered in electricity accumulator 113 and used as power P in the subsystem and / or routed to an electrical grid and / or to electricity storage facility.

[0056] In one simulation, a combined wellhead flow in conduit 102, having a temperature of about 250 °C (480 °F), and using superheated steam as auxiliary heat, produced 25,120 kW from turbine generator 152; 15,180 kW from turbine generator 156; and 4,868 kW from turbine generator 160, for a total combined 45,170 kW of electricity produced. Extraction pump 162 used 24.06 kW; cooling water pump 164 used 680.5 kW; and non-condensable gas compressor 172 used 1,178 kW. The reinjected extraction fluid in conduit 170 ranged from about 50 to about 120 °C (120 to 250 °F). Temperatures, pressures, and flow rates (mass or volume) of the various streams, for example, the steam and “heat extraction fluid” flowing into and out of the heat exchangers, will vary depending upon the subterranean geologic formation 2 with one or more ERVs, number and quality of injector well(s) 4, and number and quality of production well(s) 14.

[0057] Embodiment 200 includes using superheated steam to augment the heat harvested with the extraction fluid. Superheated steam conduit 140 routes superheated steam to primary heat exchanger 107, producing a first intermediate pressure steam that is routed via a conduit 142 from primary heat exchanger 107 to secondary heat exchanger 109. Another conduit 144 routes a second intermediate pressure steam from secondary heat exchanger 109 to tertiary heat exchanger 111, and tertiary heat exchanger produces a low pressure steam and / or steam condensate stream which is routed via conduit 146 to extraction fluid liquid collection chamber 119.

[0058] Embodiment 200 further includes previously mentioned extraction fluid extraction pump 162, cooling water supply pump 164, and a non-condensable gasescompressor 172. Non-condensable gases compressor 172 receives a flow of noncondensable gases from condenser 121 or a KO drum plumed thereto (not illustrated) via conduit 174 and discharges a higher pressure non-condensable composition via conduit 176, discharging to atmosphere or to a gas environmental cleanup facility (not illustrated) if required by local government regulations. Cooling water pump 164 receives a supply of cooling water via a conduit 178 and discharges cooling water via a conduit 180, through which cooling water traverses to extraction fluid vapor condenser 121. Warmed cooling water exits condenser 121 via conduit 182 and may be routed to a cooling tower or other water cooling facility (not illustrated). Extraction fluid extraction pump 162 receives condensed extraction fluid vapor via conduit 190 and discharges through another conduit 192 which further connects to extraction fluid liquid collection chamber 119. Electricity is supplied to pumps 162 and 164, and to compressor 172 via electrical conduits 210, 220, and 230, respectively.

[0059] Referring now to FIG. 4, a logic diagram is presented for illustrating one process embodiment 300 in accordance with the present disclosure. Process embodiment 300 is a process for harvesting heat from subterranean geologic formations (box 302), comprising: a) completing an injector well paired with one or more production wells for forming a first enhanced rock volume (FERV), the injector well having a first perforated injector horizontal lateral, and the one or more production wells having a first perforated production horizontal lateral above the first perforated injector horizontal lateral (box 304); b) harvesting heat from the FERV by pumping a first fluid at a first temperature (Tl), a first pressure (Pl), and at a first rate (Rl) into the injector well and through the first perforated injector horizontal lateral and its perforations, the first fluid contacting the FERV, transferring heat from the FERV to the first fluid to form a heated first fluidat a second temperature (T2), the first pressure (Pl) sufficient to force the heated first fluid through the first perforated production horizontal lateral and the one or more production wells (box 306); c) moving up or down hole in the injector well and building a second enhanced rock volume (SERV) by completing the injector well a second time paired with the one or more production wells for forming a second enhanced rock volume (SERV), the injector well having a second perforated injector horizontal lateral, and the one or more production wells having a second perforated production horizontal lateral above the second perforated injector horizontal lateral (box 308); d) harvesting heat from the SERV by pumping a second fluid at a third temperature (T3), a second pressure (P2), and at a second rate (R2) into the injector well and through the second perforated injector horizontal lateral and its perforations, the second fluid contacting the SERV, transferring heat from the SERV to the second fluid to form a heated second fluid at a fourth temperature (T4), the second pressure (P2) sufficient to force the heated second fluid through the second perforated production horizontal lateral and the one or more production wells (box 310); and e) repeating steps (c) and (d) at least once (box 312).

[0060] Injector pump 1 are well-known and available from various commercial suppliers, including NOV, SLB, Halliburton, Baker Hughes, and others.

[0061] The heat extraction fluid may further include propping agents, such as natural sands, bauxite particles, petroleum coke particles, and the like, which tend to maintain fractures open. A combination of fluids may be employed, and a single-path or dualpath injection strategy may be used, such as one pump creating a first flow of a first fluid in the tubing of an injector well and / or a producer well, and a second pump creating a second flow of a second fluid in the annulus of an injector well and / or aproducer well. One or more production wells extend from the surface to the subterranean geologic formation, wherein the production well can be an open hole, or cemented or uncemented liner, or selectivity segmented by ECP and sliding sleeves or pre-perforated liner.

[0062] Heat extraction fluids for extracting heat from host rock may be selected from water, brine, energizing fluids or polymer-based fluids, and may be accomplished through dual injection paths between tubing and annulus in the injector well depending on intensity and reservoir rock desired location. The tubing may be tubing in place, drill pipe, or coiled tubing. Jetting nozzles may be utilized for creating wellbore to rock fluid flow connections (connected paths). An angular abrasive material may be employed to achieve erosion and breakthrough the tubular materials separating jet nozzle tool and host rock. Dual injection in the tubing and annulus for generation of tensile fractures at desired depth may be accomplished using propping agents such as sand, bauxite and petroleum coke particles in sequences pertaining to a desired design.

[0063] Operationally, the injector pump or pumps may operate at up to 20,000 psi pump pressure rating typical for land rigs. Certain embodiments may include specialized equipment, such as high pressure pumps, coiled tubing rigs, and combinations thereof. Standpipe pressure (SPP) above 15,000 psi is considered extreme. For this case study, we notionally target between 3,000 psi and 10,000 psi standpipe pressure.

[0064] Control devices may comprise a combination of: one or more pressure control devices, also referred to as chokes; one or more temperature control devices; one or more heat extraction fluid pumping devices; one or more flow measurement devices (also referred to herein as mass flow meters or mass flow sensors); and in certain embodiments one or more accessory equipment such as one or more connectors, oneor more isolation valves, one or more pressure relief devices, among others. The specific configuration of the well, drillstring, and completions define the capabilities of each system and process embodiments. Redundancy of components may allow for extended service periods and mitigates risk of downtime due to component failure. An example would be a packer failure. In this case, isolating the failed component and enabling another one allows for continued operations, and enables evaluation and / or modification of the operational parameters to minimize the risk of failure of the new component in use.

[0065] A dedicated contingency pressure control device may be used to quickly react to sudden increases in pressure, potentially due to one or more operational pressure control devices plugging with drilled cuttings, or other reasons. This contingency pressure control device may be controlled by an automated system to open and regulate a maximum pressure set point providing time to enable additional flow paths to bypass the blocked component, if available, or to stop operations to correct the deviation.

[0066] A mass flow meter may enable monitoring the fluid (liquid and / or vapor) flow rates, and aid in comparison of fluid flow and density out of the producer well against fluid flow and density being pumped into the injector well.

[0067] During operation, one or all of T, P, mass flow rate, gas or vapor concentrations (or percentages of set point values) inside and / or outside the tubing and in the annulus may be displayed locally on Human Machine Interface (HMI), such as a laptop computer having display screen having a graphical user interface (GUI), or handheld device, or similar. In certain embodiments the HMI may record and / or transmit the data via wired or wireless communication to another HMI, such as a laptop, desktop, or hand-held computer or display. These communication links may be wired or wireless.

[0068] One or more control strategies may be employed. A pressure process control scheme may be employed, for example in conjunction with the pressure control devices and mass flow controllers. A master controller may be employed, but the disclosure is not so limited, as any combination of controllers could be used. Programmable logic controllers (PLCs) may be used.

[0069] Control strategies may be selected from proportional-integral (PI), proportionalintegral-derivative (PID) (including any known or reasonably foreseeable variations of these), and may compute a residual equal to a difference between a measured value and a set point to produce an output to one or more control elements. The controller may compute the residual continuously or non-continuously. Other possible implementations of the disclosure are those wherein the controller comprises more specialized control strategies, such as strategies selected from feed forward, cascade control, internal feedback loops, model predictive control, neural networks, and Kalman filtering techniques.

[0070] Injector wells, producer wells, pumps, and other components described herein may be built to meet ISO standards, Det Norske Veritas (DNV) standards, American Bureau of Standards (ABS) standards, American Petroleum Institute (API) standards, and / or other standards.

[0071] In certain embodiments, internal algorithms in the logic device, such as a PLC, may calculate a rate of increase or decrease in pressure inside the tubing and / or annulus. This may then be displayed or audioed in a series of ways such as “percentage to shutdown” lights or sounds, and the like on one or more GUIs. In certain embodiments, an additional function within a HMI may be to audibly alarm when the calculatedpressure rate of increase or decrease reaches a level set by the operator. In certain embodiments this alarm may be sounded at the well site, as well as remote from the well site, for example in a shipboard control room, or remote control room.

[0072] What has not been recognized or realized are systems and processes for efficient, long-term heat harvesting in subterranean geologic formations, in particular geothermal formations, that are robust and safe. Systems and processes to accomplish this without significant risk to workers is highly desirable.

[0073] Thus the systems, sub-systems, and processes described herein afford ways to perform heat harvesting in a subterranean geologic formations efficiently, safely and economically, and with significantly reduced risk of injury and discomfort to site workers.

[0074] From the foregoing detailed description of specific embodiments, it should be apparent that patentable systems, sub-systems and processes have been described. Although specific embodiments of the disclosure have been described herein in some detail, this has been done solely for the purposes of describing various features and aspects of the systems and processes, and is not intended to be limiting with respect to their scope. It is contemplated that various substitutions, alterations, and / or modifications, including but not limited to those implementation variations which may have been suggested herein, may be made to the described embodiments without departing from the scope of the appended claims. For example, some systems, subsystems, and processes of this disclosure may be devoid of certain components and / or features: for example, systems devoid of cyclone separators, or devoid of filters; systems devoid of low-strength steels; systems devoid of threaded fittings; systems devoid of welded fittings; systems devoid of casing.

Claims

What is claimed is:

1. A system for harvesting heat from subterranean geologic formations comprising: a) an injector well extending from a surface to a subterranean geologic formation, the injector well paired with one or more production wells and configured to form a first enhanced rock volume (FERV), the injector well having a first perforated injector horizontal lateral, and the one or more production wells having a first perforated production horizontal lateral above the first perforated injector horizontal lateral; b) an injection pump configured to pump a first heat extraction fluid at a first temperature (Tl), a first pressure (Pl), and at a first rate (Rl) into the injector well and through the first perforated injector horizontal lateral and its perforations, the first fluid configured to contact the FERV and transfer heat from the FERV to the first heat extraction fluid to form a heated first heat extraction fluid at a second temperature (T2), the first pressure (Pl) sufficient to force the heated first heat extraction fluid through the first perforated production horizontal lateral and the one or more production wells; c) a completion sub-system configured to seal the injector well either above or below the FERV after formation of the FERV and harvesting heat from the FERV; d) the injector well having a second perforated injector horizontal lateral, and the one or more production wells having a second perforated production horizontal lateral above the second perforated injector horizontal lateral, the completion subsystem, second perforated injector horizontal lateral, and the second perforated production horizontal lateral defining a second enhanced rock volume (SERV); e) the injection pump configured to pump a second heat extraction fluid at a third temperature (T3), a second pressure (P2), and at a second rate (R2) into the injector well and through the second perforated injector horizontal lateral and its perforations, the second heat extraction fluid configured to contact the SERV and transfer heat from the SERV to the second heat extraction fluid to form a heated secondheat extraction fluid at a fourth temperature (T4), the second pressure (P2) sufficient to force the heated second heat extraction fluid through the second perforated production horizontal lateral and the one or more production wells.

2. The system of claim 1, wherein the subterranean geologic formation is a geothermal formation, and the injector well and the one or more production wells is in dry hot rock (DHR).

3. The system of claim 2 wherein one or more of the production wells is selected from an open hole, a well comprising a cemented liner, a well comprising an uncemented liner, and a well selectively segmented by ECP and sliding sleeves or pre-perforated liner.

4. The system of claim 1 comprising: a) temperature measuring devices capable of measuring Tl, T2, T3, and T4; b) flow rate measuring devices capable of measuring R1 and R2; c) pressure measurement devices capable of measuring Pl and P2; wherein the injection pump is capable to produce R1 and Pl of the first heat extraction fluid capable of transferring at least about 760 GJ / hr. (gigajoules / hr.) of heat from the subterranean geologic formations to the first heat extraction fluid.

5. The system of claim 1 comprising: a) temperature measuring devices capable of measuring Tl, T2, T3, and T4; b) flow rate measuring devices capable of measuring R1 and R2; c) pressure measurement devices capable of measuring Pl and P2;wherein the injection pump is capable to produce R2 and P2 of the second heat extraction fluid capable of transferring at least about 730 GJ / hr. (gigajoules / hr.) of heat from the subterranean geologic formations to the second heat extraction fluid.

6. The system of claim 1 wherein the injection pump is one or more surface pumps.

7. The system of claim 1 wherein the first and second heat extraction fluids are independently selected from water, brine, viscosified fluids, energizing fluids, and polymer based fluids.

8. The system of claim 1 wherein the injector well is configured to utilize single-path injection through either an inner conduit or through an annulus between the inner conduit and casing, wherein the inner tubing is selected from in place tubing, drill pipe, and coiled tubing.

9. The system of claim 1 wherein the injector well is configured to utilize dual injection paths comprising a first injection path through an inner conduit and a second injection path through an annulus between the inner conduit and casing, and wherein the injection pump comprises a first injection pump for the first injection path and a second injection pump for the second injection path.

10. The system of claim 9 wherein the first injection pump is configured to pump the first heat extraction fluid through the first injection path, and the second injection pump is configured to pump the second heat extraction fluid through the second injection path, wherein the first and second heat extraction fluids are different in one or more physical and / or chemical properties.

11. The system of claim 1 wherein the first and / or the second heat extraction fluids comprises a propping agent.

12. The system of claim 1 further comprising a power generation sub-system fluidly and mechanically connected to a conduit configured to route a combined wellhead flow from the one or more production wells thereto, the power generation sub-system comprising a structure or structures for producing electrical power.

13. The system of claim 12 wherein the structure or structures for producing electrical power are selected from one or more knock-out drums, one or more heat exchangers, one or more pumps, one or more compressors, one or more turbine generators, one or more electrical conduits, and liquid and vapor conduits fluidly and mechanically connecting same.

14. A process for harvesting heat from subterranean geologic formations, comprising: a) completing an injector well paired with one or more production wells for forming a first enhanced rock volume (FERV), the injector well having a first perforated injector horizontal lateral, and the one or more production wells having a first perforated production horizontal lateral above the first perforated injector horizontal lateral; b) harvesting heat from the FERV by pumping a first heat extraction fluid at a first temperature (Tl), a first pressure (Pl), and at a first rate (Rl) into the injector well and through the first perforated injector horizontal lateral and its perforations, the first heat extraction fluid contacting the FERV, transferring heat from the FERV to the first heat extraction fluid to form a heated first heat extraction fluid at a second temperature (T2), the first pressure (Pl) sufficient to force the heated first heat extraction fluidthrough the first perforated production horizontal lateral and the one or more production wells; c) moving up or down hole in the injector well and building a second enhanced rock volume (SERV) by completing the injector well a second time paired with the one or more production wells for forming a second enhanced rock volume (SERV), the injector well having a second perforated injector horizontal lateral, and the one or more production wells having a second perforated production horizontal lateral above the second perforated injector horizontal lateral; d) harvesting heat from the SERV by pumping a second heat extraction fluid at a third temperature (T3), a second pressure (P2), and at a second rate (R2) into the injector well and through the second perforated injector horizontal lateral and its perforations, the second heat extraction fluid contacting the SERV, transferring heat from the SERV to the second heat extraction fluid to form a heated second fluid at a fourth temperature (T4), the second pressure (P2) sufficient to force the heated second heat extraction fluid through the second perforated production horizontal lateral and the one or more production wells; and e) repeating steps (c) and (d) at least once.

15. The process of claim 14 comprising measuring decline of heat harvesting from the FERV and / or the SERV.

16. The process of claim 14 including producing geothermal heat through the one or more producer wells, wherein the subterranean geologic formation is a geothermal formation, and the injector well and the one or more producer wells is in dry hot rock (DHR).

17. The process of claim 14 wherein the one or more producer wells are selected from an open hole, a well comprising a cemented liner, a well comprising an uncemented liner, and a well selectively segmented by ECP and sliding sleeves or pre-perforated liner.

18. The process of claim 15 wherein the measuring of decline of heat harvesting from the FERV and / or the SERV comprises measuring temperature of the first and / or second heat extraction fluids at a wellhead of the one or more producer wells.

19. The process of claim 15 wherein the measuring of decline of heat harvesting from the FERV and / or the SERV comprises measuring temperature of the first and / or second heat extraction fluids at a location in the one or more producer wells at or near the first and / or second perforated production horizontal lateral.

20. The process of claim 14 wherein the pumping is provided by one or more surface pumps.

21. The process of claim 14 wherein the first and / or second heat extraction fluids arc selected from water, brine, viscosified fluids, energizing fluids, and polymer based fluids.

22. The process of claim 14 wherein the injector well is selected from vertical / deviated injector wells and horizontal injector wells.

23. The process of claim 14 wherein the pumping utilizes single-path injection through either an inner conduit or through an annulus between the inner conduit and casing ofthe injector well, wherein the inner conduit is selected from in place tubing, drill pipe, and coiled tubing.

24. The process of claim 14 wherein the pumping utilizes dual injection paths comprising pumping a first heat extraction fluid in a first injection path through an inner conduit and pumping a second heat extraction fluid in a second injection path through an annulus between the inner conduit and casing, and wherein the injection pump comprises a first injection pump for the first injection path and a second injection pump for the second injection path.

25. The process of claim 24 wherein the first and second heat extraction fluids are different in one or more physical and / or chemical properties.

26. The process of claim 14 wherein the first fluid and / or the second heat extraction fluids comprise a propping agent.

27. The process of claim 14 further comprising routing a combined wellhead flow from the one or more production wells to a power generation sub-system fluidly and mechanically connected to the one or more production wells and generating electrical power.

28. A process for harvesting heat from subterranean geologic formations, comprising: a) completing an injector well paired with one or more production wells for forming a first enhanced rock volume (FERV), the injector well having a first perforated injector horizontal lateral, and the one or more production wells having a first perforated production horizontal lateral above the first perforated injector horizontal lateral;b) harvesting heat from the FERV by pumping a first heat extraction fluid at a first temperature (Tl), a first pressure (Pl), and at a first rate (Rl) into the injector well and through the first perforated injector horizontal lateral and its perforations, the first heat extraction fluid contacting the FERV, transferring heat from the FERV to the first heat extraction fluid to form a heated first heat extraction fluid at a second temperature (T2), the first pressure (Pl) sufficient to force the heated first heat extraction fluid through the first perforated production horizontal lateral and the one or more production wells; c) moving up or down hole in the injector well and building a second enhanced rock volume (SERV) by completing the injector well a second time paired with the one or more production wells for forming a second enhanced rock volume (SERV), the injector well having a second perforated injector horizontal lateral, and the one or more production wells having a second perforated production horizontal lateral above the second perforated injector horizontal lateral; d) harvesting heat from the SERV by pumping a second heat extraction fluid at a third temperature (T3), a second pressure (P2), and at a second rate (R2) into the injector well and through the second perforated injector horizontal lateral and its perforations, the second heat extraction fluid contacting the SERV, transferring heat from the SERV to the second heat extraction fluid to form a heated second heat extraction fluid at a second temperature (T4), the second pressure (P2) sufficient to force the heated second heat extraction fluid through the second perforated production horizontal lateral and the one or more production wells.

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