Systems and methods to boost performance in geothermal systems

Abstract

A method for extracting thermal energy from a geothermal reservoir having at least two features includes analyzing subsurface data to determine a first location of a first feature of the at least two features and a second location of a second features of the at least two features. The method further includes analyzing the subsurface data to identify first characteristics of the first feature and second characteristics of the second feature, performing a first intervention at the first location, wherein the first intervention is configured to limit fluid flow into and out of the first feature, and performing a second intervention at the second location, wherein the second intervention is configured to increase a flow rate of geothermal fluid from the second feature into a production well.

Description

SYSTEMS AND METHODS TO BOOST PERFORMANCE IN GEOTHERMAL SYSTEMSCROSS-REFERENCE TO RELATED APPLICATION(S)

[0001] This application claims priority from US Appl. No. 18 / 678,911 filed on May 30, 2024, which is a continuation-in-part of US Appl. No. 18 / 479,187 filed on October 2, 2023 and claims priority to US Provisional Appl. No. 63 / 504,797 filed on May 30, 2023, each of which are herein incorporated by reference in their entirety.FIELD

[0002] The present disclosure relates to geothermal systems that extract thermal energy from a geothermal reservoir.BACKGROUND

[0003] Geothermal systems that extract thermal energy (e.g., heat) from a geothermal reservoir are generating considerable interest. A conventional geothermal reservoir is a volume of subsurface rock that contains a natural source of pressurized geothermal fluid that is heated by natural geological processes below the Earth's surface. The pressurized geothermal fluid can include hot water or brine. The pressurized geothermal fluid is used as a source of thermal energy. A production well is drilled from the surface into and through the conventional geothermal reservoir, and may intersect one or more naturally-occurring fractures in the subsurface rock of the conventional geothermal reservoir. These naturally-occurring fractures provide a flow path of the pressurized geothermal fluid into the production well where it flows through the production well to the surface. The thermal energy from the geothermal fluid that flows to the surface can be extracted and used by an energy conversion plant for power generation, large scale heating or cooling, industrial / agricultural processes, or other geothermal applications.SUMMARY

[0004] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of theclaimed subject matter.

[0005] In an embodiment, a method for extracting thermal energy from a geothermal reservoir having at least two features includes analyzing subsurface data to determine a first location of a first feature of the at least two features and a second location of a second features of the at least two features. The method further includes analyzing the subsurface data to identify first characteristics of the first feature and second characteristics of the second feature, performing a first intervention at the first location, wherein the first intervention is configured to limit fluid flow into and out of the first feature, and performing a second intervention at the second location, wherein the second intervention is configured to increase a flow rate of geothermal fluid from the second feature into a production well.

[0006] In another embodiment, a method for extracting thermal energy from a plurality of features that extend through a geothermal reservoir includes analyzing well log data to determine a first intersection of a first feature with a production well in the geothermal reservoir and analyzing the well log data to determine a second intersection of a second feature with the production well in the geothermal system. The method further includes performing a first intervention at the first intersection using a first treatment fluid based on first characteristics of the first feature and second characteristics of the second feature and performing a second intervention after the first intervention using a second treatment fluid based on the second characteristics of the second feature, wherein the first treatment fluid and the second treatment fluid are different.

[0007] In another embodiment, a system includes a conveyance system configured to deploy a downhole tool within a production well that intersects a geothermal reservoir having a plurality of features extending therethrough. The downhole tool is configured to perform a first intervention at a first intersection of the production well with a first feature of the plurality of features, wherein the first feature corresponds to a producing feature associated with greater than a threshold amount of pressurized geothermal fluid flowing therefrom and perform a second intervention at a second intersection of the production well with a second feature of the plurality of features, wherein the second feature corresponds to a non-producing feature associated with less than the threshold amount of the pressurized geothermal fluid flowing therefrom. The system further includes a control system configured to control operation of the conveyance system to locate the downholetool at the first intersection or the second intersection, operate the downhole tool to inject a first treatment fluid into the producing feature to seal the producing feature, and operate the downhole tool to inject a second treatment fluid, different from the first treatment fluid, into the nonproducing feature to stimulate the non-producing feature.BRIEF DESCRIPTION OF THE DRAWINGS

[0008] The subject disclosure is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of the subject disclosure, in which like reference numerals represent similar parts throughout the several views of the drawings, and wherein:

[0009] FIG. 1 is a schematic diagram of an embodiment of a geothermal system having a production well that intersects and / or connects to one or more features extending through a geothermal reservoir, in accordance with aspects of the present disclosure;

[0010] FIG. 2 is a flowchart of an embodiment of a method for extracting pressurized geothermal fluid from a geothermal reservoir, in accordance with aspects of the present disclosure;

[0011] FIG. 3 is a flowchart of an embodiment of a method for an intervention process used to enhance flow of pressurized geothermal fluid from a geothermal reservoir, in accordance with aspects of the present disclosure; and

[0012] FIG. 4 is a schematic diagram of an embodiment of a downhole tool deployed in an annulus of a production well at or near the intersection of a feature of a geothermal reservoir, in accordance with an aspect of the present disclosure.DETAILED DESCRIPTION

[0013] The particulars shown herein are by way of example and for purposes of illustrative discussion of the embodiments of the subject disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the subject disclosure. In this regard, no attempt is made to show structural details in more detail than is necessary for the fundamental understanding of the subject disclosure, the description taken with the drawings making apparent to those skilled in theart how the several forms of the subject disclosure may be embodied in practice. Furthermore, like reference numbers and designations in the various drawings indicate like elements.

[0014] As used herein, the term “near wellbore region” refers to a rock formation within less than 5 feet from a wellbore surface. That is, a production wellbore having a 12-inch diameter includes a near wellbore region with an 11-foot diameter that is centered in the production wellbore.

[0015] As used herein, the term “feature” refers to a portion of a rock formation within the near wellbore region that includes pressurized geothermal fluid that may be accessed by a production wellbore.

[0016] As used herein, the term “aperture” refers to an opening or space in the near wellbore region that connects a feature to a production well at the intersection of the feature and the production well.

[0017] As used herein, the term “fracture” refers to a naturally-occurring fracture within the near wellbore region that is in fluid communication with the production well via one or more apertures.

[0018] As used herein, the term “opening a feature” means enhancing or increasing flow of geothermal fluid carried by a feature into a production well by enlarging an aperture that connects the feature to the production well or opening new flow channels that are fluidly connected to the feature or unblocking or improving the flow of geothermal fluid through an aperture that connects the feature to the production well.

[0019] As used herein, the term “near the intersection of the feature” means within less than 30 feet of a center of the intersection of the feature with the production well.

[0020] Geothermal reservoirs contain a natural source of pressurized geothermal fluid (e.g., hot water, brine, steam) that may be utilized as a source of thermal energy. For example, one or more production wells may be drilled from the surface into and through the geothermal reservoir, and the production wells may intersect one or more features (e.g., pre-existing fracture, naturally- occurring fracture, fissure, fault, rock matrix) extending through and / or existing within thesubsurface rock of the geothermal reservoir. Tn certain instances, one or more of these features may naturally provide a flow path for the pressurized geothermal fluid into the production well(s), thereby enabling the pressurized geothermal fluid to be directed to the surface via the production well(s). In certain embodiments, the geothermal reservoirs are distinguished from and / or exclude hydrocarbon reservoirs (e.g., oil and natural gas reservoirs), and may exist in geological formations different from those containing hydrocarbon reservoirs. The thermal energy from the pressurized geothermal fluid (e.g., hot fluid) that flows to the surface via the production well(s) may be extracted and used by an energy conversion plant for power generation, large scale heating and cooling, industrial and / or agricultural processes, or other geothermal applications.

[0021] In certain instances, features of the geothermal reservoir may have different characteristics (e g., physical characteristics) such that different features direct pressurized geothermal fluid into the production well at different rates and / or volumes. That is, the characteristics that define a particular feature may either enable the feature to be characterized as a producing feature in which pressurized geothermal fluid readily flows out of the feature (e.g., flows out of the feature at a threshold flow rate) or as a non-producing feature in which fluid is limited from readily flowing out of the feature (e.g., flows out of the feature at less than the threshold flow rate). For example, in certain cases, a non-producing feature may correspond to a continuous rock mass or continuous rock matrix within the subsurface rock of the geothermal reservoir that is not fluidly coupled to a production well such that less than a threshold amount of pressurized geothermal fluid flows out of the feature into the production well. Additionally, or alternatively, the non-producing feature may correspond to a fracture extending through the subsurface rock. However, an aperture of the non-producing feature at the intersection of the production well can act as a flow restrictor that limits fluid flow through the non-producing feature and into the production well (e.g., decreases pressure and / or flow rate of pressurized geothermal fluid into the production well). In either case, the amount of heat captured by the system and delivered to the surface may be limited (e.g., due to the lack of pressurized geothermal fluid directed into the production well via the non-producing feature), thereby decreasing the productivity of the system. In certain cases, one or more interventions may be performed to increase, enhance, and / or boost the flow of pressurized geothermal fluid into the production well. For example, interventions can be performed at positions in the production well that correspond to positions of the features in the production well. The interventions may be configured to open thefeatures or otherwise enhance the flow rate of pressurized geothermal fluid carried into the production well by the feature.

[0022] Unfortunately, in certain traditional systems, when interventions are performed, the producing features may be treated and / or stimulated to a greater extent relative to non-producing features. For example, during an intervention process in which treatment fluid is injected into the production well to stimulate the one or more features, a greater portion (e.g., greater volume) of the treatment fluid may be directed into the producing features relative to the non-producing features. Because a greater portion of the treatment fluid is received by the producing features, the non-producing features may receive less than a threshold amount of treatment fluid such that the non-producing features are not stimulated to the extent at which the producing features are stimulated. As a result, reduced amounts of pressurized geothermal fluid may be retrieved from the non-producing features compared to the producing features. Thus, it is now recognized that improved systems and methods for accessing pressurized geothermal fluid from non-producing features are desired.

[0023] Accordingly, embodiments of the present disclosure are directed toward boosting or improving the performance of geothermal systems that include a geothermal reservoir having producing features and non-producing features. More particularly, embodiments of the present disclosure are directed toward employing an intervention process configured to selectively target features within the geothermal reservoir with different types of fluids based on the characteristics of the feature(s) (e.g., based on whether the feature is a non-producing feature or a producing feature), thereby boosting or improving the performance of non-producing features of a geothermal reservoir. For example, the intervention process may first inject (e.g., pump) a sealing fluid (e.g., a mixture of particulates or fibers) into the production well, where the sealing fluid is configured to flow into one or more of the producing features to seal or close the one or more producing features. Particulates and / or fibers of the sealing fluid may be configured to bridge together within the feature to seal (e.g., temporarily seal) or close the feature. In certain embodiments, the particulates and / or fibers may be degradable (e.g., biodegradable) such that after a threshold amount of time passes, the particulates and / or fibers may break down to once again enable flow of pressurized geothermal fluid from the previously sealed producing feature into the production well.

[0024] The particulates and / or fibers may be sized and / or selected based on a size of the features that are targeted for sealing. For example, as noted above, one or more of the features in the geothermal reservoir may correspond to a non-producing feature having less than a threshold amount of pressurized geothermal fluid flowing therefrom, while other of the features may correspond to a producing feature having greater than a threshold amount of pressurized geothermal fluid flowing therefrom. In certain cases, the features associated with the greater flow of pressurized geothermal fluid may be larger than the features associated with the lesser flow of pressurized geothermal fluid. As such, a size (e.g., length, width, diameter, volume, etc.) of the particulates and / or fibers that make up the sealing fluid may be greater than a size of the nonproducing features associated with the lesser flow of geothermal fluid such that the particulates and / or fibers of the sealing fluid are restricted from flowing into the non-producing features. However, the size of the particulates and / or fibers that make up the sealing fluid may be less than a size of the producing features associated with the greater flow, thereby enabling the particulates and / or fibers to be directed into the producing features. Upon being directed into the producing features, the particulates and / or fibers may bridge together to limit flow of treatment fluid into the feature and / or pressurized geothermal fluid out of the feature.

[0025] After sealing the producing features with the mixture of particulates and / or fibers (e.g., after a threshold amount of time passes that enables the particles and / or fibers of the sealing fluid to bridge together to seal the producing features), a stimulation fluid may be introduced into the geothermal reservoir. For example, the stimulation fluid may correspond to a proppant slurry, an acid-based solution, a thermogenic reagent, carbon dioxide, a scale treatment fluid, or any combination thereof. Because the producing features are already sealed by the sealing fluid (e.g., mixture of particulates and / or fibers), the stimulation fluid may be directed into the smaller features to increase, boost, and / or enhance flow of pressurized geothermal fluid into the production well. For example, the stimulation fluid may increase a size of a natural fracture, thereby enabling pressurized geothermal fluid to flow more readily through the non-producing feature relative to the flow prior to the stimulation fluid being introduced. Additionally or alternatively, the stimulation fluid may increase a size of an aperture fluidly coupling the non-producing feature to the production well, which may also enable pressurized geothermal fluid to flow more readily through the feature and into the production well. In this way, an increased amount of pressurized geothermal fluid may be retrieved from a geothermal reservoir relative to traditional systems andmethods.

[0026] With the preceding in mind, FIG. 1 is a schematic view of an embodiment of a geothermal system 10. The geothermal system 10 may include various components configured to access thermal energy from a geothermal reservoir 12 of the geothermal system 10, which may correspond to a volume of subsurface rock (e.g., subterranean formation) that contains a natural source of pressurized geothermal fluid (e.g., hot water, brine, steam). For example, the geothermal system 10 may include a production well 14 drilled from the surface 16 into and through the geothermal reservoir 12, where the production well 14 intersects one or more features 18 in the subsurface rock of the geothermal reservoir 12. In certain embodiments, the geothermal reservoir 12 is formed in the subsurface rock in an area generally excluding or with insubstantial amounts of hydrocarbons (e.g., oil and natural gas), wherein the subsurface rock may have characteristics substantially different from subsurface rock associated with a hydrocarbon reservoir. Each of the one or more features 18 may contain pressurized geothermal fluid, and the geothermal system 10 may be configured to provide a fluid flow path from each of the one or more features 18 into the production well 14, thereby enabling the pressurized geothermal fluid to be directed along the fluid flow path, into the production well 14, and toward the surface 16. Indeed, because the production well 14 is drilled through a geothermal reservoir 12 generally excluding or with insubstantial amounts of hydrocarbons, the production well 14 may not retrieve hydrocarbons, and instead may retrieve pressurized geothermal fluid. The thermal energy from the geothermal fluid that flows to the surface 16 may be extracted and used by an energy conversion plant for power generation, large scale heating and cooling, industrial and / or agricultural processes, or other geothermal applications.

[0027] In certain embodiments, the geothermal reservoir 12 may include different types of features 18 having different characteristics (e.g., size, diameter, depth, size of an aperture coupling the feature 18 to the production well 14, mineralogy, etc.) such that the features 18 may be described and / or characterized relative to a rate at which fluid (e.g., pressurized geothermal fluid, injection fluid, treatment fluid) flows into and / or out of the feature 18. For example, one or more of the features 18 may correspond to a producing feature 20 (e.g., first feature type, receiving feature, producing fracture, large fracture) associated with increased relative fluid flows into and / or out of the feature (e.g., greater than a threshold flow rate of pressurized geothermal fluidinto the production well), while other of the features 18 may correspond to a non-producing feature 22 (e.g., second feature type, non-producing fracture, small fracture, continuous rock mass, continuous rock matrix) associated with decreased relative fluid flows into and / or out of the feature (e.g., less than a threshold flow rate of pressurized geothermal fluid into the production well 14). In certain embodiments, producing features may be associated with the production of at least three thousand barrels of pressurized geothermal fluid per day (3,000 bbl / day), whereas non-producing features may be associated with the production of less than one thousand barrels of pressurized geothermal fluid per day.

[0028] The characteristics of the producing features 20 may enable fluid to flow into and / or out of the producing feature 20 in a desired manner, while the characteristics of the non-producing features 22 may limit fluid from flowing into and / or out of the non-producing features in a desired manner. For example, a size (e.g., volume, depth) of the producing features 20 may be greater than a size (e.g., volume, depth) of the non-producing features 22, thereby enabling the producing features 20 to receive a greater volume of treatment or stimulation fluid relative to the nonproducing features 22. Additionally, or alternatively, each of the producing features 20 may couple to the production well 14 via an aperture 21, and each of the non-producing features 22 may couple to the production well 14 via an aperture 23. A size (e.g., diameter) of the aperture 21 of a producing feature 20 may be greater than a size of the aperture 23 of a non-producing feature 22, thereby enabling fluid (e.g., treatment fluid, stimulation fluid, pressurized geothermal fluid) to be directed through the apertures 21 associated with the producing features 20 at a greater rate relative to the rate at which fluid is directed through the apertures 23 associated with the non-producing features 22. It should be appreciated that while the non-producing feature 22 is illustrated as a fracture, in certain embodiments, the non-producing feature 22 may correspond to a continuous rock mass or continuous rock matrix (e.g., a portion of the subsurface rock) of the geothermal reservoir 12 that is not fluidly coupled to the production well 14. Thus, in certain embodiments, the non-producing feature 22 may not include an aperture 23.

[0029] It should be appreciated that each of the features 18 may have unique characteristics that define the respective feature 18. For example, in certain embodiments, each of the features 18 that correspond to producing features 20 may have different characteristics relative to other producing features 20, thereby enabling fluid to flow into and / or out of each of the producingfeatures 20 at different volumes and / or flow rates relative to other producing features 20. Similarly, each of the features 18 that correspond to non-producing features 22 may have different characteristics relative to other non-producing features 22, thereby enabling fluid to flow into and / or out of each of the non-producing features 22 at different volumes and / or flow rates relative to other non-producing features 22. It should further be appreciated that in certain embodiments, it may be desirable to seal a non-producing feature 22, thereby enabling a different non-producing feature 22 to be selectively targeted for improvements, as described in greater detail below.

[0030] In the illustrated embodiment, the producing feature 20 has a surface depth 24 that is a vertical distance from the surface 16, and a measured depth 26 along the production well 14 that is a length of the production well 14 to the aperture 21 of the producing feature 20. As may be appreciated, the measured depth 26 may be different than the surface depth 24 based at least in part on a pathway of the production well 14 and / or a pathway of the producing feature 20. Similarly, the non-producing feature 22 has a surface depth 28 that is a vertical distance from the surface 16, and a measured depth 30 along the production well 14 that is a length of the production well 14 to the aperture 23 of the non-producing feature 22. In the illustrated embodiment, the wellbore of the production well 14 is completed with a perforated liner 32 (e.g., slotted liner) with perforations in the intervals of the production well 14 that intersect the features 18. In alternative embodiments, the wellbore of the production well 14 may be completed with a perforated casing or as an open wellbore.

[0031] In certain embodiments, a downhole tool may be deployed into the production well 14 and the downhole tool may be operated to perform one or more interventions that open the one or more features 18 (e.g., increase the permeability of the features) or otherwise enhance and / or increase the flow rate of pressurized geothermal fluid into the production well 14 of the geothermal system 10. For example, in certain embodiments, the intervention process may be configured to enlarge an aperture (e.g., aperture 21, aperture 23) of a feature 18, thereby reducing pressure loss at the aperture while increasing the flow area and / or flow rate through the aperture (e.g., from the production well 14 to the feature 18 and / or from the feature 18 to the production well 14). Additionally, or alternatively, the intervention process may be configured to enlarge the feature 18 itself. For example, the intervention process may be configured to increase a size of the feature (e.g., depth, volume of the feature), thereby enabling a greater amount of pressurized geothermalfluid to be contained within the feature 18. In turn, a greater amount of pressurized geothermal fluid may be retrieved from the feature 18 relative to a feature 18 that has not been treated by an intervention process.

[0032] FIG. 2 is a flowchart of an example process 100 or workflow which includes an intervention that opens a feature (e.g., features 18 of FIG. 1) that intersects the production well (e.g., production well 14 of FIG. 1) or otherwise enhances or increases the flow rate of pressurized geothermal fluid into the production well of the system (e.g., geothermal system 10 of FIG. 1). In certain embodiments, certain steps of the process 100 may be performed by downhole equipment, whereas other steps of the process 100 may be performed by a processor-based computing device or controller or any other suitable computing device(s) or controller(s). Furthermore, the blocks of the process 100 may be performed in the order disclosed herein or in any other suitable order. For example, certain blocks of the process 100 may be performed concurrently. In addition, in certain embodiments, one or more of the blocks of the process 100 may be repeated or omitted.

[0033] In block 102, a production well (e.g., production well 14 of FIG. 1) is drilled such that the production well intersects one or more features (e.g., naturally-occurring features, naturally- occurring fractures, pre-existing fractures) of a geothermal reservoir (e.g., features 18 of the geothermal reservoir 12 of FIG. 1). As noted above, the one or more features may extend through the geothermal reservoir. In certain embodiments, each of one or more of the features may be fluidly coupled to the production well via an aperture (e.g., opening) of the feature that is intersected by the production well. The one or more features may contain pressurized geothermal fluid (e.g., hot water, brine, steam), which may be collected by the production well and delivered to the surface to be used as thermal energy.

[0034] In block 104, well log data (e.g., subsurface data) may be analyzed (e.g., by a processorbased computing device) to determine a position of each of the one or more features intersected by the production well drilled in block 102. For example, borehole pressure measurements, caliper measurements, resistivity measurements, acoustic or ultrasonic borehole imaging measurements, and / or other downhole measurements may be analyzed to determine a wellbore depth (e.g., position, measured depth) for each of the one or more features. These measurements may be performed while drilling or by a wireline tool after drilling. For example, borehole pressuremeasurements may be analyzed for pressure loss while drilling. When the drilling crosses or otherwise intersects a feature, the borehole pressure will decrease. The depth of such pressure loss can be detected and used as the measured depth (e.g., position) of the feature in the production well. In certain embodiments, the measured depth may correspond to a wellbore depth of an aperture of a fracture (e.g., feature) in the production well. In certain embodiments, the subsurface data may be obtained from direct measurement of the production well, from surface measurements, or from offset wells.

[0035] In block 106, a downhole tool may be located in the production well at a measured depth corresponding to the position of the feature as determined in block 104. The downhole tool may be located in the production well via a drill pipe, coiled tubing, or wireline. Accurately positioning the downhole tool for the intervention at or near the feature increases the effectiveness of the intervention. That is, an intervention performed within less than three feet, less than two feet, or less than one foot of the feature that intersects the production well can greatly improve the efficacy of the intervention to reduce the pressure loss of the pressurized geothermal fluid and / or to increase the flow rate of the pressurized geothermal fluid into the production well.

[0036] In block 108, the downhole tool can be operated to perform an intervention that selectively opens one or more of the features or otherwise enhances and / or increases the flow rate of pressurized geothermal fluid from the geothermal reservoir into the production well of the system. For example, as discussed in greater detail below, the intervention process may include a step in which a sealing fluid is first introduced into the production well to selectively seal or close off one or more features (e.g., producing features). After sealing one or more of the features with the sealing fluid, one or more additional features (e.g., features that were not sealed during the first step) may be selectively targeted for stimulation. For example, during a second step of the intervention process, a treatment fluid may be directed into the one or more additional features to increase the flow area and / or to reduce the pressure loss at the intersection of the feature and the production well (e.g., reduce pressure loss at an aperture of the feature), thereby enhancing and / or increasing the flow rate of pressurized geothermal fluid from the one or more additional features, as described in greater detail below.

[0037] In optional block 110, the operations of blocks 106 and 108 may be repeated withrespect to additional feature(s) that intersect the production well in order to increase the flow rate of pressurized geothermal fluid into the production well. In optional block 112, debris resulting from the intervention of block 108 may be cleaned out and / or removed from the production well (e.g., via coiled tubing), thereby further increasing the flow rate of pressurized geothermal fluid into the production well.

[0038] FIG. 3 is a flowchart of an example process 200 (e.g., intervention process) for stimulating (e.g., selectively stimulating) one or more features of a geothermal reservoir to enhance and / or increase the flow rate of pressurized geothermal fluid from the geothermal reservoir into a production well of a geothermal system. That is, the process 200 may be utilized to increase the flow area and / or to reduce the pressure loss at the intersection of a feature (e.g., non-producing feature 22) and a production well (e.g., production well 14), thereby increasing the flow rate of pressurized geothermal fluid from the feature into the production well. In certain embodiments, steps of the process 200 may correspond to steps performed during the process 100 of FIG. 2 (e.g., blocks 104, 106, 108) to locate and / or stimulate (e.g., selectively target, selectively stimulate, perform an intervention on) features of the geothermal reservoir, thereby increasing the flow area and / or reducing pressure loss associated with such features. In this way, the flow rate of pressurized geothermal fluid carried by the feature(s) into the production well may increase, thereby increasing productivity of the geothermal system. In certain embodiments, the process 200 may be localized with respect to a set of features (e.g., a target interval) within the geothermal reservoir. For example, in certain embodiments, packers (e.g., inflatable packers, straddle packers) may be deployed into the production well at measured depths above and below the targeted set of features to isolate the features and enable targeted treatment, as described below.

[0039] In certain embodiments, certain steps of the process 200 may be performed by a processor-based computing device or controller or any other suitable computing device(s) or controller(s), whereas other steps of the process 200 may be performed by downhole equipment. Furthermore, blocks of the process 200 may be performed in the order disclosed herein or in any other suitable order. For example, certain blocks of the process 200 may be performed concurrently. In addition, in certain embodiments, one or more blocks of the process 200 may be repeated or omitted.

[0040] In block 202, well log data (e.g., subsurface data) may be analyzed to determine a position (e.g., a location) of each of the one or more features intersected by a production well drilled through a geothermal reservoir. Thus, in certain embodiments, block 202 may correspond to block 104 of process 100. In addition to determining a position or location of each of the one or more features that are intersected by the production well, the well log data may be analyzed to identify one or more physical and / or operating characteristics of each of the one or more features. The physical characteristics may include, but are not limited to, a size (e.g., length, depth, volume) of the feature, a size (e.g., diameter, circumference) of an aperture fluidly coupling the feature to the production well, a material composition of the feature (e.g., whether the feature includes scale deposits and / or the type of scale deposits, a type of subsurface rock in the geothermal reservoir), and the like. The operating characteristics, which may be at least partially defined by the physical characteristics, may include a flow rate of pressurized geothermal fluid from the feature into the production well (e.g., before an intervention process is performed) and / or a flow rate of fluid into the feature from the production well (e.g., a capacity or ability of the feature to receive treatment fluid).

[0041] In certain embodiments, other types of data may be analyzed in block 202 to identify a location of the one or more features and the physical and / or operating characteristics of the one or more features. For example, in certain embodiments, one or more of the features may change or adjust over time (e.g., as a result of pressurized geothermal fluid flowing out of the feature(s), based on an intervention process targeting one or more of the features). Accordingly, in certain embodiments, real-time data may be analyzed (e.g., data received from electrical and / or optical telemetry cables extending along the production well) to identify the changes to the physical and / or operating characteristics of the one or more features. Such real-time data may be utilized by the process 200 to adjust certain operating parameters, thereby increasing the efficiency of the process 200, as discussed in greater detail below. By using the well log data, real-time data, and / or other types of data to identify the location and physical and / or operating characteristics of each of the one or more features, each of the one or more features may be identified and / or characterized as a producing feature or a non-producing feature based on a relative flow rate of fluid into and / or out of the feature. As noted above, it should be appreciated that while a feature may be characterized as a non-producing feature, certain non-producing features may be associated with different flow rates into and / or out of the feature relative to other non-producing features. Similarly, differentproducing features may be associated with different flow rates into and / or out of the feature relative to other producing features.

[0042] Upon identifying and / or characterizing each of the features intersected by the production well (e.g., using the various types of data analyzed in block 202), one or more treatment fluids (e.g., sealing fluid, stimulation fluid) may be designed to selectively target one or more of the features. In certain embodiments, the treatment fluids introduced into the production well may perform different functions and may be configured to target different features based on the respective characteristics of each of the features. For example, in block 204, a first treatment fluid (e.g., a sealing fluid, degradable fluid, bridging fluid, plugging fluid) may be designed to target one or more of the producing features identified in block 202. The first treatment fluid may correspond to a sealing fluid (e.g., degradable sealing fluid) configured to flow into a particular feature to seal the feature, thereby blocking and / or limiting fluid flow into and / or out of the feature. For example, the sealing fluid may be a mixture of particles and / or fibers (e.g., a multi-phase flow with solids carried in a liquid). In certain embodiments, the particles may be spherical or rodshaped, and the fibers may include a linear or crimped morphology. Additionally, in certain embodiments, different sized particles and / or fibers may be employed based on the characteristics of the target feature. That is, a first sealing fluid configured to target a first feature may include particles and / or fibers having a first size, and a second sealing fluid configured to target a second feature having differing characteristics from the first feature may include particles and / or fibers having a second size, different than the first size, based on the differing characteristics of the first and second features. As the particles and / or fibers are injected into a particular feature, the particles and / or fibers may couple to one another to limit and / or block fluid flow into and / or out of the feature. In certain embodiments the sealing fluid may be configured to limit or block a threshold percentage of fluid flow out of the feature. For example, greater than a threshold percentage (e.g., 80%, 90%, 95%, or more) of the pressurized geothermal fluid flowing from the feature prior to introduction of the sealing fluid may be blocked from flowing out of the feature after introduction of the sealing fluid into the feature. Additionally, or alternatively, the sealing fluid may be configured to occupy greater than a threshold area or volume of the feature (e.g., sealing fluid occupies at least 75%, 85%, 90%, or more of the feature)

[0043] In certain embodiments, the sealing fluid may have a low viscosity when firstintroduced into the feature. However, after a first threshold amount of time passes, the particles and / or fibers may be configured to couple to one another (e.g., bridge together) to form a composite material (e.g., material matrix) such that the viscosity of the sealing fluid increases, thereby limiting fluid flow into and / or out of the feature. In certain embodiments, the sealing fluid may be degradable such that the particles and / or fibers of the sealing fluid are configured to break down (e.g., dissolve, decrease in viscosity) after a threshold amount of time, thereby enabling features treated with the sealing fluid to direct pressurized geothermal fluid into the production well after the threshold amount of time elapses. For example, the sealing fluid may be degradable (e.g., biodegradable) based on certain environmental conditions (e.g., temperature, pressure, moisture, etc.). Additionally, or alternatively, the sealing fluid may be configured to degrade over a time duration that is sufficient for the downhole tool to perform the process 200.

[0044] In certain embodiments, the sealing fluid may be designed based on certain characteristics of the features (e.g., producing features, non-producing features) within the geothermal reservoir. For example, the sealing fluid may be designed and / or configured such that the sealing fluid is capable of being directed into certain of the features (e.g., producing features) but incapable of being directed into other of the features (e.g., non-producing features). That is, the size (e.g., diameter, length, width) of the particles and / or fibers that make up the sealing fluid may be selected and / or designed based on the physical characteristics of the features (e.g., size of an aperture that fluidly couples a feature to the production well) within the geothermal reservoir. For example, a size of the particles that make up the sealing fluid may be smaller than a size of an aperture fluidly coupling a producing feature to the production well, thereby enabling the sealing fluid to be directed through the aperture and into the producing feature. Conversely, a size of the particles that make up the sealing fluid may be larger than a size of an aperture fluidly coupling a non-producing feature to the production well such that less than a threshold amount of sealing fluid is directed into the non-producing feature. In this way, certain of the features (e.g., producing features) may be sealed and / or closed off, while other of the features remain open to receive a second treatment fluid (e.g., stimulation fluid), as described in greater detail below. It should be appreciated that, in certain embodiments, one or more non-producing features may be treated with the first treatment fluid, thereby enabling other non-producing features to readily receive the second treatment fluid. That is, in certain embodiments, the size of the particles and / or fibers may be selected and / or designed such that the sealing fluid is capable of flowing into certain non-producing features but incapable of flowing into other non-producing features.

[0045] In block 206, a second treatment fluid (e.g., stimulation fluid) may be designed to target one or more of the features (e.g., non-producing features) identified in block 202. The second treatment fluid may correspond to a stimulation fluid configured to flow into a particular feature to stimulate the feature (e.g., increase the permeability of the feature), thereby enhancing and / or increasing the flow of pressurized geothermal fluid from the feature into the production well. In certain embodiments, the stimulation fluid may be configured to increase a degree of opening of a feature and / or an aperture fluidly coupling the feature to the production well. For example, the stimulation fluid may include, but is not limited to a proppant slurry, an acid-based solution (e.g., hydrogen chloride, chelant, mud acid, organic mud acid, solvents, clay stabilizers and retarded hydrogen chloride mixture), a thermogenic reagent, carbon dioxide, a scale treatment fluid, or any combination thereof. The stimulation fluid may be diverted into one or more of the features (e.g., non-producing features) to increase the flow area of a feature by a respective mechanism (e.g., fracture, wormholes, etching, micro cracks, etc.). Thus, the stimulation fluid may be designed based on the characteristics of the one or more features.

[0046] In certain embodiments, the stimulation fluid may be configured to chemically react with the feature (e.g., with the subsurface rock surrounding the feature) and / or with scales embedded within the feature (e.g., carbonaceous scale, siliceous scale). Thus, in certain embodiments, the stimulation fluid may be designed based on the material composition of a targeted feature and / or a material composition of scales embedded within the target feature. For example, for subsurface rock formations having carbonate fractions or calcite scales, a hydrogen chloride solution may be utilized to stimulate the feature. For subsurface rock formations having silica or sandstone fractions, a chelant-based solution, a mud acid solution, and / or an organic mud acid solution may be utilized to stimulate the feature. Further, for formations that include drilling mud debris, one or more solvents may be utilized to stimulate the feature. Thus, the stimulation fluid may be designed and / or optimized to achieve a target reaction rate and / or target reaction pattern with the feature, thereby enabling the stimulation fluid to enhance and / or increase flow of pressurized geothermal fluid from the feature into the production well. For example, in certain instances, when the reactivity (e.g., reaction rate) between the stimulation fluid and the feature exceeds an upper limit threshold value, the stimulation fluid may be spent or consumed at a ratethat does not enable the stimulation fluid to penetrate the feature to a desired extent (e.g., desired depth). Similarly, when the reactivity is below a lower limit threshold value, the stimulation fluid may not be reactive enough to penetrate the feature to the desired extent. Accordingly, the stimulation fluid may be designed (e.g., based on modeling and / or testing) to achieve a target reaction rate and / or target reaction pattern with a feature that penetrates or otherwise stimulates the feature in a desired manner.

[0047] It should be appreciated that while the second treatment fluid is described above as being designed to target non-producing features (e.g., pre-existing features, naturally-occurring fractures), in certain embodiments, the second treatment fluid may be designed to target the subsurface rock of the geothermal reservoir. That is, in certain embodiments, the first treatment fluid may be utilized to seal or block off any pre-existing features (e.g., producing features, nonproducing features), thereby enabling the second treatment fluid to target portions of the subsurface rock that include pressurized geothermal fluid embedded therein. For example, the second treatment fluid may be designed and / or optimized to achieve a target reaction rate with the subsurface rock such that the permeability of the subsurface rock is increased based on a type of the subsurface rock of the geothermal reservoir (e.g., carbonate dominant formation, silica or sandstone dominant formation). Additionally, or alternatively, an injection rate of the stimulation fluid may be tested and optimized to achieve a target reaction pattern (e.g., wormhole, fracture) with the subsurface rock of the geothermal reservoir. In this way, portions of the geothermal reservoir that were previously untapped or underutilized may be stimulated to retrieve pressurized geothermal fluid.

[0048] After designing and / or optimizing the first and second treatment fluids, in block 208, a downhole tool may be deployed into the production well at a measured depth corresponding to the position of a feature as determined in block 202. Thus, block 208 may correspond to block 106 in the process 100. Accurately positioning the downhole tool for the intervention at or near the feature increases the effectiveness of the intervention. In certain embodiments, one or more components may be utilized to isolate one or more of the features, thereby enabling the intervention process 200 to be localized with respect to a feature.

[0049] For example, FIG. 4 is a schematic diagram of an embodiment of a downhole tool 300deployed into an annulus 304 of a production well 302 via coiled tubing 306 to stimulate one or more features 312 of a geothermal reservoir 313. In the illustrated embodiment, a first packer 308 and a second packer 310 are positioned in the annulus 304 of the production well 302 at a measured depth corresponding to a position of an aperture 311 of a feature 312 intersected by the production well 312. The first and second packers 308, 310 (e.g., annular packers) can be positioned and / or set at measured depths above and below the aperture 311 of the feature 312 to isolate (e.g., seal off) an interval 314 of the production well 302 that intersects the feature 312. For example, the first packer 308 may be set within the interval 314 such that the first packer 308 is positioned a threshold distance 316 (e.g., two feet, five feet, ten feet, fifteen feet, thirty feet) above the aperture 311 of the feature 312, and the second packer 310 may be set within the interval 314 such that the second packer 310 is positioned a threshold distance 318 (e.g., two feet, five feet, ten feet, fifteen feet, thirty feet) below the aperture 311 of the feature 312. Upon setting the first and second packers 302, 304, the first or second treatment fluid may be directed through the coiled tubing 306 and into the downhole tool 300 to selectively target the feature 312 isolated by the first and second packers 308, 310, as described in greater detail below.

[0050] It should be appreciated that while a single feature 312 is illustrated as being isolated by the first and second packers 302, 304, in other embodiments, multiple features 312 having different characteristics may be isolated by the first and second packers 302, 304 (e.g., positioned within the interval 314), and different treatment fluids (e.g., first treatment fluid, second treatment fluid) may be directed through the downhole tool 300 to treat the different features 312. For example, the interval 314 may include any number (e.g., one, two, three, four, or more) of producing features and any number of non-producing features (e.g., one, two, three, four, or more), and each of the producing features and non-producing features may be selectively targeted by the downhole tool 300, as described below.

[0051] In the illustrated embodiment, the production well 302 is completed with a perforated liner 318 (e.g., slotted liner) at least in the interval 314 where the feature 312 intersects the production well 302. To this end, in certain embodiments, the production well 302 may include one or more spacers 320 positioned between the perforated liner 318 and the geothermal reservoir 313 to improve a stability of the production well 302. However, it should be appreciated that the production well 302 may be completed using other methods. For example, in certainembodiments, the production well 302 may be completed by a cemented casing, and the cemented casing may be perforated to expose the rock at or near the aperture 311 of the feature 312. Further, it should be appreciated that for cases in which the feature 312 intersects the annulus 304 of the production well 302 about the circumference of the production well 302, the downhole tool 300 may be operated to provide the first or second treatment fluid about the circumference of the production well 302.

[0052] Returning to FIG. 3, once the downhole tool has been deployed to the measured depth corresponding to a position of a feature, the first treatment fluid or the second treatment fluid may be directed into the feature to either limit or block fluid flow into and / or out of the feature or to stimulate fluid flow out of the feature. For example, in block 210, after positioning the downhole tool at a measured depth corresponding to a target producing feature, the first treatment fluid (e.g., sealing fluid) may be directed (e.g., injected) into the producing feature to selectively seal or block off the producing feature. For example, the sealing fluid may be pumped down through the production well (e.g., via coiled tubing) under pressure to the downhole tool, which operates to inject the sealing fluid into the target feature. As noted above, the sealing fluid may correspond to a mixture of particles and / or fibers configured to bridge together within the feature to seal the feature. For example, the particles and / or fibers may couple to one another within the feature, thereby creating a sealing fluid structure that occupies a cavity or volume defined by the feature. Because the cavity or volume defined by the feature is occupied by the sealing fluid (e.g., sealing fluid structure), fluid flow into and / or out of the feature may be reduced, limited, or blocked. In this way, additional fluid introduced into the production well (e.g., second treatment fluid, stimulation fluid) may not flow into the feature (e.g., producing feature) targeted in block 208 (e.g., by virtue of the sealing fluid present within the targeted feature).

[0053] It should be appreciated that blocks 208 and 210 may be repeated to treat a number of target features (e.g., target producing features) that intersect the production well. For example, upon sealing a particular producing feature of the geothermal reservoir, the process 200 may return to block 208 to relocate the downhole tool at a position corresponding to another producing feature. In this way, each of the one or more target producing features within an interval of the production well may be sealed or blocked off before introducing the second treatment fluid into the production well, as described in greater detail below. In certain embodiments, at block 212, the process 200may determine whether each of the target producing features have been treated and / or injected with the sealing fluid. If a determination is made that one or more target producing features have not yet been treated with the sealing fluid, the process 200 may return to block 208 to relocate the downhole tool at a position corresponding to one of the remaining target producing features. If a determination is made that each of the target producing features have been sealed by the sealing fluid, the process 200 may to return to block 208 to locate the downhole tool at a position corresponding to a target non-producing feature.

[0054] After positioning the downhole tool at a measured depth corresponding to a target nonproducing feature, the process 200 may proceed to block 214 in which the second treatment fluid (e.g., stimulation fluid) may be directed (e.g., injected) into the target non-producing feature to selectively stimulate, open, or otherwise enhance the flow of pressurized geothermal fluid from the target non-producing feature (e.g., increase the permeability of the non-producing feature). For example, the stimulation fluid may be pumped down through the production well (e.g., via coiled tubing) under pressure to the downhole tool, which operates to inject the stimulation fluid into the target feature. As noted above, the stimulation fluid may correspond to a proppant slurry, an acidbased solution (e.g., hydrogen chloride, chelating agent or chelant and retarded hydrogen chloride mixture), a thermogenic reagent, carbon dioxide, a scale treatment fluid, or any combination thereof configured to interact and / or react with the feature to increase a flow rate of pressurized geothermal fluid into the production well.

[0055] In certain embodiments, the downhole tool may be operated to direct the stimulation fluid into the target non-producing feature at a desired rate as determined in block 206, thereby enabling the stimulation fluid to penetrate the feature in a desired manner (e.g., according to a particular pattern). In certain embodiments, the stimulation fluid may be configured to increase a permeability of the feature and / or increase a degree of opening of an aperture fluidly coupling a feature to the production well. Additionally, or alternatively, the simulation fluid may be configured to increase a size or volume of the one or more features, thereby enabling an increased amount of stimulation fluid to be directed into the feature. For example, in certain embodiments, a first stimulation fluid may be introduced into the production well to increase a size of an aperture or a size of a feature. Thereafter, a second stimulation fluid (e.g., different from the first stimulation fluid) may be directed into the one or more features (e.g., by virtue of increasing thedegree of opening of an aperture coupling the feature to the production well), where the second stimulation fluid may interact with the geothermal reservoir to enhance and / or increase the flow of pressurized geothermal fluid from the feature into the production well. Further, it should be appreciated that, in certain embodiments, the target non-producing feature may correspond to a portion of the geothermal reservoir (e.g., subsurface rock) that does not include a natural fracture or fissure that provides a fluid flow path from the subsurface rock into the production well. That is, in certain embodiments, the subsurface rock itself may be treated with the stimulation fluid to increase the permeability of the subsurface rock and to generate fluid flow paths (e.g., fractures, wormholes, and the like) for pressurized geothermal fluid from the subsurface rock into the production well.

[0056] In certain embodiments, it may be desirable to increase the degree of opening and / or increase a size of one or more of the features before the stimulation fluid is introduced into the production well. For example, in certain embodiments, other intervention methods (e.g., perforating) may be employed to increase a size of the features before the stimulation fluid is introduced into the feature. By increasing the size of the feature before introducing the stimulation fluid, a greater volume of stimulation fluid may be directed into the feature, thereby enabling the feature to be stimulated to a greater extent (e.g., by virtue of a greater volume of stimulation fluid reacting and / or interacting with the feature). In this way, an increased amount of pressurized geothermal fluid may be captured by the production well.

[0057] Further, it should be appreciated that blocks 208 and 214 may be repeated to treat a number of target features (e.g., target non-producing features) that intersect the production well. For example, upon directing a stimulation fluid into a particular non-producing feature, the process 200 may return to block 208 to relocate the downhole tool at a position corresponding to another non-producing feature. In this way, each of the one or more target non-producing features within an interval of the production well may be selectively stimulated.

[0058] Technical effects of the present disclosure include systems and methods for selectively targeting one or more features of a geothermal reservoir to enhance, boost, and / or increase the flow of pressurized geothermal fluid from the feature into a well (e g., geothermal well, production well). In particular, systems and methods are described herein that identify characteristics of thevarious features within a geothermal reservoir, and selectively target the one or more features based on the characteristics of the features (e.g., based on whether the feature is a producing feature associated with greater than a threshold amount of pressurized geothermal fluid flowing therefrom or a non-producing feature associated with less than the threshold amount of pressurized geothermal fluid flowing therefrom). For example, present embodiments may employ an intervention process that injects a sealing fluid (e.g., first treatment fluid) into the production well, where the sealing fluid is configured to flow into the one or more producing features to seal or close the one or more producing features. In certain embodiments, the sealing fluid may be a mixture of particles and / or fibers configured to bridge together within the feature to seal or close off the feature. A size of the particles and / or fibers that make up the sealing fluid may be selected and / or designed based on the characteristics of the features in the geothermal reservoir. For example, the size of the particles and / or fibers may be selected such that the sealing fluid is capable of flowing into the producing features but incapable of flowing into the non-producing features. Further, in certain embodiments, the sealing fluid may be degradable such that after a threshold amount of time passes and / or based on certain conditions, the particulates and / or fibers may break down to once again enable flow of pressurized geothermal fluid from the previously sealed producing feature into the production well.

[0059] Once the sealing fluid is injected into each of the producing features to limit, block, or reduce fluid flow into and / or out of the producing features (e.g., to seal or close off the producing features), a stimulation fluid (e.g., second treatment fluid), different from the sealing fluid, may be injected into the production well, where the stimulation fluid is configured to flow into the one or more non-producing features to increase, boost, and / or enhance flow of pressurized geothermal fluid from the non-producing features into the production well (e.g., increase the permeability of the non-producing features). For example, the stimulation fluid may correspond to a proppant slurry, an acid-based solution, a thermogenic reagent, carbon dioxide, a scale treatment fluid, or any combination thereof. Because the producing features are sealed by the sealing fluid, the stimulation fluid may be directed into the non-producing features to increase a size of the feature, increase a size of an aperture fluidly coupling the feature to the production well, or otherwise increase the flow of pressurized geothermal fluid from the non-producing features into the production well. In this way, an increased amount of pressurized geothermal fluid may be retrieved from a geothermal reservoir relative to traditional systems and methods.

[0060] The subject matter described in detail above may be defined by one or more clauses, as set forth below.

[0061] A method for extracting thermal energy from a geothermal reservoir having at least two features includes analyzing subsurface data to determine a first location of a first feature of the at least two features and a second location of a second features of the at least two features. The method further includes analyzing the subsurface data to identify first characteristics of the first feature and second characteristics of the second feature, performing a first intervention at the first location, wherein the first intervention is configured to limit fluid flow into and out of the first feature, and performing a second intervention at the second location, wherein the second intervention is configured to increase a flow rate of geothermal fluid from the second feature into a production well.

[0062] The method of the preceding clause, wherein the first feature corresponds to a producing feature, wherein the producing feature directs at least three thousand barrels of the geothermal fluid into the production well per day.

[0063] The method of any preceding clause, wherein the second feature corresponds to a nonproducing feature, wherein the non-producing feature directs less than one thousand barrels of the geothermal fluid into the production well per day.

[0064] The method of any preceding clause, wherein the first intervention includes injecting a sealing fluid into the first feature, wherein the sealing fluid is configured to close the first feature to limit the fluid flow into and out of the first feature.

[0065] The method of any preceding clause, wherein the sealing fluid is degradable.

[0066] The method of any preceding clause, wherein the sealing fluid includes a mixture of particles and fibers configured to bridge together within the first feature.

[0067] The method of any preceding clause, including selecting the sealing fluid based on the first characteristics of the first feature and the second characteristics of the second feature.

[0068] The method of any preceding clause, wherein a size of the particles and fibers of the sealing fluid is based on a size of the first feature and a size of the second feature.

[0069] The method of any preceding clause, wherein the size of the particles and fibers of the sealing fluid is less than a first size of a first aperture associated with the first feature and greater than a second size of a second aperture associated with the second feature.

[0070] The method of any preceding clause, wherein the second intervention includes injecting a stimulation fluid into the second feature, wherein the stimulation fluid is configured to stimulate the second feature to increase the flow of the geothermal fluid from the second feature into the production well.

[0071] The method of any preceding clause, wherein the stimulation fluid comprises a proppant slurry, an acid-based solution, a thermogenic reagent, carbon dioxide, a scale treatment fluid, or any combination thereof.

[0072] A method for extracting thermal energy from a plurality of features that extend through a geothermal reservoir includes analyzing well log data to determine a first intersection of a first feature with a production well in the geothermal reservoir and analyzing the well log data to determine a second intersection of a second feature with the production well in the geothermal system. The method further includes performing a first intervention at the first intersection using a first treatment fluid based on first characteristics of the first feature and second characteristics of the second feature and performing a second intervention after the first intervention using a second treatment fluid based on the second characteristics of the second feature, wherein the first treatment fluid and the second treatment fluid are different.

[0073] The method of the preceding clause, wherein the first feature corresponds to a producing feature associated with greater than a threshold flow rate of pressurized geothermal fluid, and wherein the second feature corresponds to a non-producing feature associated with less than the threshold flow rate of the pressurized geothermal fluid.

[0074] The method of any preceding clause, wherein the producing feature is a first producing feature of a plurality of producing features intersecting the production well, and wherein the method includes performing the first intervention at each of the plurality of producing features before performing the second intervention at the non-producing feature.

[0075] The method of any preceding clause, wherein the first treatment fluid includes amixture of particles configured to couple to one another within the first feature to block the pressurized geothermal fluid from flowing out of the first feature.

[0076] The method of any preceding clause, wherein a size of a particle of the mixture of particles is selected based on the first characteristics of the producing feature and the second characteristics of the non-producing feature, wherein the first characteristics include a first size of a first aperture coupling the producing feature to the production well, and wherein the second characteristics include a second size of a second aperture coupling the non-producing feature to the production well, wherein the size of the particle is greater than the second size of the second aperture and less than the first size of the first aperture.

[0077] The method of any preceding clause, wherein the second treatment fluid includes a proppant slurry, an acid-based solution, a thermogenic reagent, carbon dioxide, a scale treatment fluid, or any combination thereof, configured to stimulate the non-producing feature to increase a flow rate of the pressurized geothermal fluid from the non-producing feature.

[0078] The method of any preceding clause, wherein the acid-based solution is configured to achieve a target reaction rate and a target reaction pattern with the non-producing feature.

[0079] A system includes a conveyance system configured to deploy a downhole tool within a production well that intersects a geothermal reservoir having a plurality of features extending therethrough. The downhole tool is configured to perform a first intervention at a first intersection of the production well with a first feature of the plurality of features, wherein the first feature corresponds to a producing feature associated with greater than a threshold amount of pressurized geothermal fluid flowing therefrom and perform a second intervention at a second intersection of the production well with a second feature of the plurality of features, wherein the second feature corresponds to a non-producing feature associated with less than the threshold amount of the pressurized geothermal fluid flowing therefrom. The system further includes a control system configured to control operation of the conveyance system to locate the downhole tool at the first intersection or the second intersection, operate the downhole tool to inject a first treatment fluid into the producing feature to seal the producing feature, and operate the downhole tool to inject a second treatment fluid, different from the first treatment fluid, into the non-producing feature to stimulate the non-producing feature.

[0080] The system of the preceding clause, wherein the first treatment fluid corresponds to a degradable mixture of particles that is designed based on physical characteristics of the producing feature and the non-producing feature, and wherein the second treatment fluid corresponds to a proppant slurry, an acid-based solution, a thermogenic reagent, carbon dioxide, a scale treatment fluid, or any combination thereof, that is designed based on the physical characteristics of the nonproducing feature.

[0081] The foregoing description, for purpose of explanation, has been described with reference to specific embodiments. However, the illustrative discussions above are not intended to be exhaustive or to limit the disclosure to the precise forms disclosed. Many modifications and variations are possible in view of the above teachings. Moreover, the order in which the elements of the methods described herein are illustrated and described may be re-arranged, and / or two or more elements may occur simultaneously. The embodiments were chosen and described in order to best explain the principals of the disclosure and its practical applications, to thereby enable others skilled in the art to best utilize the disclosure and various embodiments with various modifications as are suited to the particular use contemplated.

[0082] Finally, the techniques presented and claimed herein are referenced and applied to material objects and concrete examples of a practical nature that demonstrably improve the present technical field and, as such, are not abstract, intangible or purely theoretical. Further, if any claims appended to the end of this specification contain one or more elements designated as “means for [perform]ing [a function]...” or “step for [perform]ing [a function]...”, it is intended that such elements are to be interpreted under 35 U.S.C. 112(f). However, for any claims containing elements designated in any other manner, it is intended that such elements are not to be interpreted under 35 U.S.C. 112(f).

[0083] Further, in certain embodiments, the intervention process (e.g., the injection of sealing fluid and / or treatment fluid) may extend about the circumference of the production well, for example, in the case where the feature intersects the production well about the circumference of the production well.

Claims

CLAIMS:

1. A method for extracting thermal energy from a geothermal reservoir having at least two features, the method comprising: analyzing subsurface data to determine a first location of a first feature of the at least two features and a second location of a second feature of the at least two features; analyzing the subsurface data to identify first characteristics of the first feature and second characteristics of the second feature; performing a first intervention at the first location, wherein the first intervention is configured to limit fluid flow into and out of the first feature; and performing a second intervention at the second location, wherein the second intervention is configured to increase a flow rate of geothermal fluid from the second feature into a production well.

2. The method of claim 1, wherein the first feature corresponds to a producing feature, wherein the producing feature directs at least three thousand barrels of the geothermal fluid into the production well per day.

3. The method of claim 2, wherein the second feature corresponds to a non-producing feature, wherein the non-producing feature directs less than one thousand barrels of the geothermal fluid into the production well per day.

4. The method of claim 1, wherein the first intervention comprises injecting a sealing fluid into the first feature, wherein the sealing fluid is configured to close the first feature to limit the fluid flow into and out of the first feature.

5. The method of claim 4, wherein the sealing fluid is degradable.

6. The method of claim 4, wherein the sealing fluid comprises a mixture of particles and fibers configured to bridge together within the first feature.

7. The method of claim 6, comprising selecting the sealing fluid based on the firstcharacteristics of the first feature and the second characteristics of the second feature.

8. The method of claim 6, wherein a size of the particles and fibers of the sealing fluid is based on a size of the first feature and a size of the second feature.

9. The method of claim 8, wherein the size of the particles and fibers of the sealing fluid is less than a first size of a first aperture associated with the first feature and greater than a second size of a second aperture associated with the second feature.

10. The method of claim 1, wherein the second intervention comprises injecting a stimulation fluid into the second feature, wherein the stimulation fluid is configured to stimulate the second feature to increase the flow of the geothermal fluid from the second feature into the production well.

11. The method of claim 10, wherein the stimulation fluid comprises a proppant slurry, an acidbased solution, a thermogenic reagent, carbon dioxide, a scale treatment fluid, or any combination thereof.

12. A method for extracting thermal energy from a plurality of features that extend through a geothermal reservoir, the method comprising: analyzing well log data to determine a first intersection of a first feature with a production well in the geothermal reservoir; analyzing the well log data to determine a second intersection of a second feature with the production well in the geothermal system; performing a first intervention at the first intersection using a first treatment fluid based on first characteristics of the first feature and second characteristics of the second feature; performing a second intervention after the first intervention using a second treatment fluid based on the second characteristics of the second feature, wherein the first treatment fluid and the second treatment fluid are different.

13. The method of claim 12, wherein the first feature corresponds to a producing featureassociated with greater than a threshold flow rate of pressurized geothermal fluid, and wherein the second feature corresponds to a non-producing feature associated with less than the threshold flow rate of the pressurized geothermal fluid.

14. The method of claim 13, wherein the producing feature is a first producing feature of a plurality of producing features intersecting the production well, the method comprising: performing the first intervention at each of the plurality of producing features before performing the second intervention at the non-producing feature.

15. The method of claim 13, wherein the first treatment fluid comprises a mixture of particles configured to couple to one another within the first feature to block the pressurized geothermal fluid from flowing out of the first feature.

16. The method of claim 15, wherein a size of a particle of the mixture of particles is selected based on the first characteristics of the producing feature and the second characteristics of the nonproducing feature, wherein the first characteristics comprise a first size of a first aperture coupling the producing feature to the production well, and wherein the second characteristics comprise a second size of a second aperture coupling the non-producing feature to the production well, wherein the size of the particle is greater than the second size of the second aperture and less than the first size of the first aperture.

17. The method of claim 13, wherein the second treatment fluid comprises a proppant slurry, an acid-based solution, a thermogenic reagent, carbon dioxide, a scale treatment fluid, or any combination thereof, configured to stimulate the non-producing feature to increase a flow rate of the pressurized geothermal fluid from the non-producing feature.

18. The method of claim 17, wherein the acid-based solution is configured to achieve a target reaction rate and a target reaction pattern with the non-producing feature.

19. A system, comprising: a conveyance system configured to deploy a downhole tool within a production well thatintersects a geothermal reservoir having a plurality of features extending therethrough; the downhole tool configured to: perform a first intervention at a first intersection of the production well with a first feature of the plurality of features, wherein the first feature corresponds to a producing feature associated with greater than a threshold amount of pressurized geothermal fluid flowing therefrom; and perform a second intervention at a second intersection of the production well with a second feature of the plurality of features, wherein the second feature corresponds to a non-producing feature associated with less than the threshold amount of the pressurized geothermal fluid flowing therefrom; and a control system configured to control operation of the conveyance system to locate the downhole tool at the first intersection or the second intersection, wherein the control system is configured to: operate the downhole tool to inject a first treatment fluid into the producing feature to seal the producing feature; and operate the downhole tool to inject a second treatment fluid, different from the first treatment fluid, into the non-producing feature to stimulate the non-producing feature.

20. The system of claim 19, wherein the first treatment fluid corresponds to a degradable mixture of particles that is designed based on physical characteristics of the producing feature and the non-producing feature, and wherein the second treatment fluid corresponds to a proppant slurry, an acid-based solution, a thermogenic reagent, carbon dioxide, a scale treatment fluid, or any combination thereof, that is designed based on the physical characteristics of the nonproducing feature.

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