# US 12,006,809 B2 · Methods for enhancing and maintaining heat transfer efficiency between geothermal heat and injection fluid > Agents: this data is available as JSON from the patentgrep API and MCP server — see https://patentgrep.com/llms.txt - Number: US 12,006,809 B2 - Document ID: US12006809B2 - Status: Granted - Kind: B2 - Application number: 17/716,571 - Filed: 2022-04-08 - Published: 2023-10-12 - Granted: 2024-06-11 - Earliest claimed: 2022-04-08 - Assignees: Halliburton Energy Services, Inc. - Applicants: Halliburton Energy Services, Inc. - Inventors: Philip D. Nguyen; Ronald Glen Dusterhoft - Web page: https://patentgrep.com/patent/US12006809B2 ## CPC - E21B 43/267: reinforcing fractures by propping - E21B 43/17: Interconnecting two or more wells by fracturing or otherwise attacking the formation ({E21B43/2405,} E21B43/247 take precedence) - E21B 43/283: {in association with a fracturing process} - E21B 43/305: {comprising at least one inclined or horizontal well} - E21B 47/07: Temperature - F24T 10/20: using underground water as working fluid; using working fluid injected directly into the ground, e.g. using injection wells and recovery wells - F24T 2010/53: {Methods for installation} - E21B: EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS - F24T: GEOTHERMAL COLLECTORS; GEOTHERMAL SYSTEMS ## Abstract Methods and compositions for enhancing the flow rate and heat transfer efficiency of wellbores and/or propped fractures for use in geothermal operations are provided. In some embodiments, the methods comprise: injecting an etching agent into an injection inlet of a first wellbore penetrating a first portion of a subterranean formation, wherein the injection inlet is disposed at a first location at or near a surface of the subterranean formation; injecting a working fluid having a first temperature into the injection inlet; allowing at least a portion of the working fluid to flow from the injection inlet to a production outlet of a second wellbore penetrating a second portion of the subterranean formation; and producing the portion of the working fluid out of the production outlet at a first rate and at a second temperature that is higher than the first temperature. ## Claims ### Claim 1 A method comprising: injecting an etching agent into an injection inlet of a first wellbore penetrating a first portion of a subterranean formation, wherein the injection inlet is disposed at a first location at or near a surface of the subterranean formation; injecting a working fluid having a first temperature into the injection inlet; allowing at least a portion of the working fluid to flow from the injection inlet to a production outlet of a second wellbore penetrating a second portion of the subterranean formation, wherein the production outlet is disposed at a second location at or near the surface of the subterranean formation; and producing the portion of the working fluid out of the production outlet at a first rate and at a second temperature that is higher than the first temperature, wherein the first wellbore and the second wellbore are different. ### Claim 2 (depends on 1) The method of claim 1, further comprising etching, with the etching agent, one or more conductive channels in fluid communication between the first wellbore and the second wellbore. ### Claim 3 (depends on 1) The method of claim 1, further comprising injecting a scale inhibitor into the injection inlet as a component of one or more of a drilling fluid, a treatment fluid, a fracturing fluid, and the working fluid. ### Claim 4 (depends on 3) The method of claim 3, wherein both the etching agent and the scale 4 inhibitor comprise a chelant. ### Claim 5 (depends on 1) The method of claim 1, further comprising drilling at least a portion of the first wellbore from the surface to penetrate at least the first portion of the subterranean formation. ### Claim 6 (depends on 1) The method of claim 1, further comprising: injecting a fracturing fluid into the first wellbore at a pressure sufficient to create at least a first set of fractures in the subterranean formation extending from and in fluid communication with the first wellbore; and injecting a first plurality of proppant particulates into at least the first set of fractures, wherein the second wellbore penetrates at least the second portion of the subterranean formation from the surface, and wherein a second set of fractures extends from and is in fluid communication with the second wellbore, and the first set of fractures is in fluid communication with the second set of fractures. ### Claim 7 (depends on 6) The method of claim 6, further comprising injecting the etching agent into the first wellbore before injecting the fracturing fluid such that the etching agent is placed in one or more distal ends of the first set of fractures. ### Claim 8 (depends on 1) The method of claim 1, wherein the etching agent is injected into the injection inlet as a component of one or more of a drilling fluid, a treatment fluid, a fracturing fluid, and the working fluid. ### Claim 9 (depends on 1) The method of claim 1, wherein the etching agent is one or more of an acid or a chelant. ### Claim 10 (depends on 1) The method of claim 1, further comprising injecting one or more solid slow-release scale inhibitors into the injection inlet as a component of one or more of a drilling fluid, a treatment fluid, a fracturing fluid, and the working fluid, the one or more solid slow-release scale inhibitors comprising one or more of a delayed acid and a delayed chelant. ### Claim 11 (depends on 1) The method of claim 1, further comprising: halting or slowing a rate of production of the working fluid from the production outlet for a first period of time; and resuming or increasing the rate of production of the working fluid from the production outlet at or near the first rate after the first period of time. ### Claim 12 (depends on 1) The method of claim 1, wherein allowing the at least the portion of the working fluid to flow from the injection inlet to the production outlet of the second wellbore penetrating the second portion of the subterranean formation comprises allowing the at least a portion of the working fluid to flow from the injection inlet and, via a first set of fractures extending from and in fluid communication with the first wellbore and a second set of fractures extending from and in fluid communication with the second wellbore, to the production outlet of the second wellbore penetrating the second portion of the subterranean formation. ### Claim 13 A method comprising: injecting a working fluid having a first temperature into an injection inlet of a first wellbore penetrating a first portion of a subterranean formation, wherein the injection inlet is disposed at a first location at or near a surface of the subterranean formation; allowing at least a portion of the working fluid to flow from the injection inlet to a production outlet of a second wellbore penetrating a second portion of the subterranean formation, wherein the production outlet is disposed at a second location at or near the surface of the subterranean formation; producing the portion of the working fluid out of the production outlet at a first rate and at a second temperature that is higher than the first temperature; halting or slowing a rate of production of the working fluid from the production outlet for a first period of time; and resuming or increasing the rate of production of the working fluid from the production outlet at or near the first rate after the first period of time, wherein the first wellbore and the second wellbore are different. ### Claim 14 (depends on 13) The method of claim 13, further comprising drilling at least a portion of the first wellbore from the surface to penetrate at least the first portion of the subterranean formation. ### Claim 15 (depends on 12) The method of claim 12, further comprising: injecting a fracturing fluid into the first wellbore at a pressure sufficient to create at least a first set of fractures in the subterranean formation extending from and in fluid communication with the first wellbore; and injecting a first plurality of proppant particulates into at least the first set of fractures, wherein the second wellbore penetrates at least the second portion of the subterranean formation from the surface, and wherein a second set of fractures extends from and is in fluid communication with the second wellbore, and the first set of fractures is in fluid communication with the second set of fractures. ### Claim 16 (depends on 13) The method of claim 13, further comprising injecting an etching agent into the injection inlet as a component of one or more of a drilling fluid, a treatment fluid, a fracturing fluid, and the working fluid. ### Claim 17 (depends on 16) The method of claim 16, further comprising etching, with the etching agent, one or more conductive channels capable of facilitating fluid communication between the first wellbore and the second wellbore. ### Claim 18 (depends on 16) The method of claim 16, wherein the etching agent is one or more of an acid or a chelant. ### Claim 19 (depends on 13) The method of claim 13, further comprising injecting a scale inhibitor into the injection inlet as a component of one or more of a drilling fluid, a treatment fluid, a fracturing fluid, and the working fluid. ### Claim 20 A method comprising: injecting an etching agent into an injection inlet of a first wellbore penetrating a first portion of a subterranean formation; injecting a scale inhibitor into the injection inlet; injecting a working fluid having a first temperature into the injection inlet disposed at a first location at or near a surface of the subterranean formation; allowing at least a portion of the working fluid to flow from the injection inlet to a production outlet of a second wellbore penetrating a second portion of the subterranean formation, wherein the production outlet is disposed at a second location at or near the surface of the subterranean formation; producing the portion of the working fluid out of the production outlet at a first rate and at a second temperature that is higher than the first temperature; halting or slowing a rate of production of the working fluid from the production outlet for a first period of time; and resuming or increasing the rate of production of the working fluid from the production outlet at or near the first rate after the first period of time, wherein the etching agent and the scale inhibitor comprise N-(phosphonomethyl) iminodiacetic acid (PMIDA), wherein the first wellbore and the second wellbore are different. ### Claim 21 (depends on 20) The method of claim 20, further comprising: injecting a fracturing fluid into the first wellbore at a pressure sufficient to create at least a first set of fractures in the subterranean formation extending from and in fluid communication with the first wellbore; and injecting a first plurality of proppant particulates into at least the first set of fractures, wherein the second wellbore penetrates at least the second portion of the subterranean formation from the surface, and wherein a second set of fractures extends from and is in fluid communication with the second wellbore, and the first set of fractures is in fluid communication with the second set of fractures.