Microseismic monitoring of a horizontal EGS system

Abstract

The present invention relates to systems and methods for monitoring microseismic activity in a geothermal well system using fiber optic sensing technology. The system includes fiber optic cables installed in multiple wells of the geothermal well system. The fiber optic cables enable simultaneous collection of distributed acoustic sensing (DAS) data, strain measurements, and temperature data. By detecting and localizing microseismic events during stimulation and operation of the geothermal well system, seismic activity is maintained within safety thresholds, providing for safe and effective extraction from the geothermal well system.

Description

MICROSEISMIC MONITORING OF A HORIZONTAL EGS SYSTEM STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0001] This invention was made with government support under DE-AR001604 awarded by the U.S. Department of Energy ARPA-E. The government has certain rights in this invention. CLAIM OF PRIORITY

[0002] This international application claims the benefit of U.S. Provisional Patent Application Serial No.63 / 550,291, filed on February 6, 2024, titled “MICROSEISMIC MONITORING OF A HORIZONTAL EGS SYSTEM,” the contents of which is incorporated by reference herein in its entirety. FIELD OF THE INVENTION

[0003] The present invention relates to real-time monitoring of seismic activity for applications in industries such as oil and gas, mining, and geothermal energy. BACKGROUND

[0004] Monitoring seismic activity has widespread application in geothermal technologies. For example, seismic monitoring is useful for assessing and managing the risk of induced seismicity in geothermal operations. Through seismic monitoring, seismic events, which may be triggered by fluid injection or extraction, may be detected and analyzed. By analyzing these seismic events, a geothermal operation may be adjusted, such as by adjusting injection rates or adjusting injection pressures, to mitigate the risk of potentially damaging seismic events. Thus, through seismic monitoring, potentially damaging seismic events may be proactively prevented, protecting infrastructure and populations from these potentially damaging seismic events. However, monitoring seismic activity in geothermal operations faces various technical challenges and limitations.BRIEF DESCRIPTION OF THE DRAWINGS

[0005] Some examples are shown for purposes of illustration and not limitation in the figures of the accompanying drawings. In the drawings, which are not necessarily drawn to scale, like numerals may describe similar components in different views or examples. It should be understood that additional and alternative examples are possible without departing from the principles of the subject matter described herein.

[0006] FIG. 1 illustrates an example of a natural resource system, in accordance with examples described herein.

[0007] FIG. 2 illustrates an example of a monitoring system at a natural resource system, in accordance with examples described herein.

[0008] FIG. 3 illustrates an example of wells in a natural resource system, in accordance with examples described herein.

[0009] FIG. 4 illustrates an example of a monitoring system installation, in accordance with examples described herein.

[0010] FIG. 5 illustrates an example of seismic data provided by a monitoring system in a natural resource system, in accordance with examples described herein.

[0011] FIG. 6 illustrates an example of seismic events detected in a natural resource system, in accordance with examples described herein.

[0012] FIG. 7 illustrates an example of seismic data provided by a monitoring system, in accordance with examples described herein.

[0013] FIG. 8 illustrates an example of seismic data provided by a monitoring system, in accordance with examples described herein.

[0014] FIG. 9 illustrates an example of seismic events detected by a monitoring system in a natural resource system, in accordance with examples described herein.

[0015] FIG. 10 illustrates an example technique for monitoring seismic data, in accordance with examples described herein.

[0016] FIG. 11 illustrates an example of a machine upon which any one or more of the techniques discussed herein may perform, in accordance with examples described herein.DETAILED DESCRIPTION

[0017] While monitoring seismic activity has widespread application in geothermal technologies, the technologies involved in monitoring seismic activity face various technical challenges and limitations. Traditionally, the geothermal industry has relied on surface seismic measurements, including broadband sensors and passive seismic emissions, to monitor seismicity. However, the presence of shallow unconsolidated sediments leads to severe scattering attenuation, posing technical challenges and limitations in achieving acceptable signal-to-noise ratio (SNR) in seismic data collected at surface stations. In contrast, the unconventional oil and gas industry utilizes three- component (3C) geophones for collecting seismic data, but these 3C geophones are rated for operating temperatures (e.g., below 180°C) that are less than the operating temperatures (e.g., greater than 200°C) at which the geothermal industry operates. Furthermore, deployment of 3C geophones faces technical challenges and limitations because tractors for deploying the 3C geophones cannot operate at the operating temperatures (e.g., greater than 200°C) at which the geothermal industry operates, rendering the tractors incapable of deploying the 3C geophones in horizontal wells. Thus, monitoring seismic activity in geothermal operations faces various technical challenges and limitations with respect to gathering seismic data.

[0018] The systems and techniques described herein seeks to address these and other technical challenges and limitations arising in the field of geothermal technologies. For example, through integration of Distributed Acoustic Sensing (DAS)-based microseismic and low-frequency DAS (or high-resolution Distributed Strain Sensing) information, along with temperature sensing capabilities provided by Distributed Temperature Sensing, seismic data is acquired for monitoring seismic activity. The acquisition of this seismic data is facilitated by permanent fiber optic cables deployed behind well casing, temporary wireline encapsulated fiber optic cables, temporary single-use fiber optic cables, and wireline fiber optic cables integrated with 3C geophone sensors or an optical accelerometer array (e.g., a hybrid fusion array). Permanent fiber optic cables advantageously offer high-quality data recording capabilities. Temporary fiber optic cables advantageously offer flexible deployment within the well casing, obviating well design changes, and facilitate seismic activitymonitoring in multiple wells. Wireline fiber optic cables integrated with 3C geophone sensors or an optical accelerometer array (e.g., a hybrid fusion array) advantageously scale for monitoring multiple wells and multiple stages. For example, the hybrid fusion array is deployed in an adjacent horizontal monitoring well and moved stage by stage in sync with a nearby stimulated well. This enables acquisition of low-frequency strain data, which informs on fracture hits or Fracture Driven Interactions (FDI).

[0019] In some examples, the present invention provides for techniques for monitoring microseismic activity in a geothermal well system. The techniques include installing fiber optic cables in the wells of the geothermal well system, which may include vertical wells and horizontal wells. The fiber optic cables facilitate continuous monitoring of seismic activity in the geothermal well system by continuously recording microseismic data. During seismic events, such as during stimulation operations or crossflow operations, microseismic data is acquired from the fiber optic cables. Microseismic events within and around the geothermal well system are detected from the microseismic data. The locations of the microseismic events are determined using the microseismic data. By combining the microseismic data from the fiber optic cables of the geothermal well system, location uncertainty associated with the seismic events are minimized.

[0020] In some examples, permanent fiber optic cables are installed behind the casing of the wells of the geothermal well system. The permanent fiber optic cables are clamped to the casing during installation of the casing downhole, ensuring proper coupling with the surrounding formation. This installation of the permanent fiber optic cables allows for reliable data collection throughout the operational lifetime of the fiber optic cables. Furthermore, permanent installation behind casing allows the fiber optic cables to acquire improved signal quality compared to some temporary fiber optic cable deployments, which may suffer from degraded signal quality due to poor coupling with the surrounding formation.

[0021] In some examples, temporary fiber optic cables are deployed for monitoring seismic activity in the geothermal well system. Temporary fiber optic cables include wireline encapsulated fiber optic cables, single-use fiber optic cables, and hybrid fusion array configurations that combine fiber opticsensors with 3C geophone sensors or optical accelerometer arrays. While temporary fiber optic cables may suffer from degraded signal quality, temporary fiber optic cables are more flexibly deployed. Temporary fiber optic cables may be repositioned stage by stage and do not require well design modifications.

[0022] In some examples, the microseismic data acquired by the fiber optic cables include Distributed Acoustic Sensing (DAS) data. The DAS data includes acoustic signals and vibrations detected and measured along the entire length of the fiber optic cables. The DAS data includes continuous, real-time measurements of strain rate captured along the fiber optic cables. The DAS data provides high-resolution measurements and precise monitoring of seismic activity, including detection of P-wave and S-wave arrivals. In some examples, event locations are determined using waveform stacking methods based on the DAS data.

[0023] In some examples, a Short-Term Average / Long-Term Average (STA / LTA) based triggering method is used for detecting microseismic events from the microseismic data. This detection methodology distinguishes between microseismic events from background noise. Following the triggering method, waveform stacking on progressively refined grids (e.g., from a relatively coarser grid to a relatively finer grid) provides for accurate event localization.

[0024] In some examples, microseismic event locations are determined by utilizing microseismic data from vertical fiber optic cables in vertical monitoring wells and horizontal fiber optic cables in horizontal monitoring wells. Microseismic data from vertical fiber optic cables are used to estimate the depth, or location in the vertical plane, of microseismic events. Microseismic data from horizontal fiber optic cables are used to estimate the aerial location, or location in the horizontal plane, of microseismic events. In some examples, events are detected on multiple fiber optic cables, and the uncertainty in event location is reduced to distinct regions through integration of the seismic data from vertical fiber optic cables and horizontal fiber optic cables. Thus, by employing multiple fiber optic cables, highly accurate three-dimensional event location determinations of microseismic events are made based on the microseismic data acquired by the fiber optic cables.

[0025] In some examples, microseismic event locations are determined using a multi-step grid search process. A coarse grid search is performed to identifyapproximate locations of microseismic events. A refined grid search is performed at a finer grid scale to enhance the accuracy of the approximate locations of the microseismic events. The grid search process is repeated at finer grid scales for a recursive fine grid search. For each grid point, the events of the microseismic data are flattened based on a precalculated travel time grid. The point in the grid with the highest energy is determined to be the source microseismic location.

[0026] In some examples, the microseismic data is used to determine fracture geometry parameters and microseismic diffusion rates. The fracture geometry parameters include fracture orientation, fracture length, and fracture height. For example, analysis of microseismic data enables determination of fracture orientation, with analysis of seismic events confirming stress orientations. In some examples, analysis of microseismic diffusion rates facilitates correlation of seismicity rate with pressure measurements to confirm microseismic activity. The analysis of fracture geometry parameters and microseismic diffusion rates facilitate analysis of fracture network development and fluid movement within the geothermal well system.

[0027] In some examples, microseismic data and low-frequency strain rate data are collected from the fiber optic cables to analyze fracture behavior. For example, microseismic events may appear as stripes in the low-frequency strain rate data, enabling correlation between the two data types. This correlation reveals information about, for example, fracture extension and distribution of microseismic events. In some examples, the low-frequency strain data is used to confirm fracture heights determined based on the microseismic data.

[0028] In some examples, a crossflow test is performed within the geothermal well system to evaluate flow connectivity and monitor seismic activity. During the crossflow test, seismic activity is monitored and evaluated to confirm the relationship between pressure and seismic activity within the stimulated volume of the geothermal well system. By monitoring the seismic activity, seismic events are detected and confirmed to be within the confines of the stimulated volume and to have magnitudes within acceptable threshold limits. In this way, the crossflow test confirms the feasibility of the geothermal well system for extraction of geothermal energy.

[0029] In some examples, the fiber optic cables are designed to operate at temperatures of 200°C or higher to enable monitoring of seismic activity in high- temperature geothermal environments. In some examples, each fiber optic cable comprises at least two single-mode fibers and two multi-mode fibers to provide redundancy and enable different types of measurements.

[0030] The present invention has application to oil and gas activities, such as waterflooding, steam flooding, steam assisted gravity drainage, and enhanced oil recovery. The present application has application to geothermal energy activities, where thermal energy is extracted from subsurface formations by circulating a working fluid, such as water or carbon dioxide, through the formation and recovering the heated fluid. It should be understood that while the examples described herein involve the recovery of geothermal resources and hydrocarbon resources from beneath the surface of the earth, the present invention is not so limited. Thus, the present invention described herein, including the monitoring of microseismic activity, may find applicability in the recovery of minerals and ores, and other resources within the ground.

[0031] FIG. 1 illustrates an example 100 of a natural resource system 102, in accordance with examples described herein. For example, the natural resource system 102 may pump fluid or gas from one or more geothermal energy sources. Typically, in the production of natural resources from formations within the earth a well or borehole is drilled into the earth to the location where the natural resource is believed to be located. These natural resources may be a heat source for geothermal energy, a hydrocarbon reservoir, containing natural gas, crude oil and combinations of these; the natural resource may be fresh water; or it may be some other natural resource that is located within the ground.

[0032] Generally, when a well is drilled into these formations the natural resources rarely flow into and out of the formation, and into the well at rates, durations and amounts that are economically viable. This problem can relate to the viscosity of the natural resource, the porosity of the formation, the geology of the formation, the formation pressures, and the perforations that place the production tubing in the well in fluid communication with the formation, to name a few.

[0033] In drilling a well, an initial borehole is made into the earth, and then, subsequent and smaller diameter boreholes are drilled to extend the overall depthof the borehole. In this manner, as the overall borehole gets deeper its diameter becomes smaller; resulting in what can be envisioned as a telescoping assembly of holes with the largest diameter hole being at the top of the borehole closest to the surface of the earth.

[0034] Typically, when completing a well, it is necessary to perform a perforation operation. In general, when a well has been drilled and casing (e.g., a metal pipe) is run to the prescribed depth, the casing is typically cemented in place by pumping cement down and into the annular space between the casing and the earth. The casing, among other things, prevents the hole from collapsing and fluids from flowing between permeable zones in the annulus. Thus, this casing forms a structural support for the well and a barrier to the earth.

[0035] Boreholes are generally formed and advanced by using mechanical drilling equipment having a rotating drilling tool (e.g., a bit). For example, when creating a borehole in the earth, a drilling bit is extending to and into the earth and rotated to create a hole in the earth. In general, to perform the drilling operation the bit must be forced against the material to be removed with a sufficient force to exceed the shear strength, compressive strength, or combinations thereof, of that material.

[0036] As illustrated in FIG.1, the natural resource system 102 can inject a fluid or a gas through a subsurface 104 via an injection well 108 to fractures 110a, 110b, 110c. The fractures 110a, 110b, 110c can be part of an enhanced geothermal system, which can be a man-made reservoir created where there is hot rock but insufficient or little natural permeability or fluid saturation. In some instances, fluid or gas can be injected through the injection well 108 to cause the fractures 110a, 110b, 110c to open or re-open to creating permeability. In some instances, fluid or gas can be injected through the injection well 108 as part of a flow through the fractures 110a, 110b, 110c. The flow through the fractures 110a, 110b, 110c can be enhanced through reservoir stimulation. Here, stimulation of multiple fractures, such as the fractures 110a, 110b, 110c, allows for an area to be stimulated in a series of smaller stimulations, minimizing local stress perturbations. The stimulation of multiple fractures provides for access to significantly more of the reservoir and provides additional flow opportunities, increasing overall flow rate. For example, through multizone stimulation flowrates of 40-80 kg / s for commercial production may be achieved where stimulation of a single fracture may fail to achieve a flow greater than 25 kg / s.

[0037] As illustrated in FIG.1, fluid or gas can flow from the fractures 110a, 110b, 110c to the natural resource system 102 through the subsurface 104 via a production well 106. The natural resource system 102 can extract energy (e.g., heat, thermal energy) from the fluid or the gas from the fractures 110a, 110b, 110c. As illustrated in FIG.1, the injection well 108 and the production well 106 can be horizontal wells. The injection well 108 and the production well 106 can have limited entry completion designs to maximize thermal sustainability. In general, limited entry completion designs refer to well stimulation techniques that effectively treat multiple zones simultaneously. Through limited entry completion designs, even stimulation and uniform flow can be achieved.

[0038] FIG. 2 illustrates an example 200 of a monitoring system at a natural resource system, in accordance with examples described herein. The monitoring system includes seismic monitoring stations 202a, 202b, 202c, 202d, 202e, 202f, 202g, 202h, 202i distributed across the natural resource system. The seismic monitoring stations include surface stations installed on hard rock formations and shallow borehole stations. The monitoring system includes horizontal wells 204, 206 and a vertical monitoring well 208. As further explained herein, the monitoring system demonstrates the efficacy of monitoring seismic activity using fiber optic cables to detect and localize microseismic events during well stimulation and operation.

[0039] FIG. 3 illustrates an example 300 of wells in a natural resource system, in accordance with examples described herein. The example 300 is a cross- sectional view of the natural resource system showing a vertical monitoring well 302, a deviated well 308, and horizontal wells 304, 306. In the example 300, permanent fiber optic cables are installed behind the casing of the vertical monitoring well 302, the deviated well 308, and the horizontal wells 304, 306 to enable monitoring of seismic activity during well stimulation and operation. An Extended Reach Drilling (ERD) pressure gauge 310 may be located in the natural resource system to confirm the measurements of the fiber optic cables. The relative positioning of the wells facilitates monitoring of microseismic events and allows for the determination of fracture geometry parameters, including fracture orientation, length, and height.

[0040] FIG. 4 illustrates an example 400 of a monitoring system installation, in accordance with examples described herein. The example 400 is a cross- sectional view of a well assembly 404 incorporating fiber optic monitoring capabilities. The well assembly 404 includes fiber optic cables 402 installed behind the casing, secured by cable clamps. The fiber optic cables 402 are designed to operate at temperatures exceeding 200°C and comprise at least two single-mode fibers and two multi-mode fibers, allowing for simultaneous collection of distributed acoustic sensing (DAS) data, strain rate data, and temperature measurements. The permanent installation of the fiber optic cables 402 behind the casing facilitates improved coupling with the surrounding formation, which is advantageous for achieving high-quality microseismic signal detection and maintaining the integrity of the monitoring system throughout the operational lifetime of the well. As illustrated in FIG. 4, the fiber optic cables 402 reach a depth 406 of about 7900 ft. However, it should be understood that various lengths of fiber optic cables 402 are possible, allowing for the fiber optic cables 402 to reach various depths.

[0041] FIG. 5 illustrates an example 500 of seismic data provided by a monitoring system in a natural resource system, in accordance with examples described herein. The example 500 shows microseismic data acquired by a horizontal fiber optic cable during well stimulation activities. In the example 500, the microseismic data is acquired employing a Gauge Length (GL) of 5 meters and a sampling rate of 10kHz along a 300m section of the horizontal fiber optic cable. The microseismic data includes DAS data acquired during the well stimulation activities. As illustrated in FIG. 5, the microseismic data has a favorable signal-to-noise (SNR) ratio, allowing an microseismic event to be clearly detected with a peak 502.

[0042] FIGS.2-5 collectively illustrate various aspects of a microseismic monitoring system used in an Enhanced Geothermal System (EGS). For example, FIG. 2 illustrates a surface-level monitoring network with seismic monitoring stations 202a, 202b, 202c, 202d, 202e, 202f, 202g, 202h, 202i positioned around horizontal wells 204, 206 and a vertical monitoring well 208. FIG. 3 illustrates a cross-sectional view of the horizontal wells 304, 306 and the vertical monitoring well 302. The cross-sectional view of FIG.3 also illustrates an ERD pressure gauge 310. FIG.4 illustrates an example installation of fiberoptic cables in these horizontal wells and the vertical monitoring well. The seismic monitoring stations 202a, 202b, 202c, 202d, 202e, 202f, 202g, 202h, 202i and the ERD pressure gauge 310 acquire seismic data that verify the efficacy and accuracy of the seismic data captured by fiber optic cables in the horizontal wells and the vertical monitoring well. For example, the seismic data illustrated in FIG.5 is verified by the seismic data acquired by the seismic monitoring stations 202a, 202b, 202c, 202d, 202e, 202f, 202g, 202h, 202i and the ERD pressure gauge 310.

[0043] FIG. 6 illustrates an example 600 of seismic events detected in a natural resource system, in accordance with examples described herein. The seismic events are detected using seismic data collected by fiber optic cables in the natural resource system. As illustrated in FIG. 6, a map view 602 and a cross- sectional view 610 illustrate microseismic event distributions during well stimulation activities. The map view 602 and the cross-sectional view 610 illustrate the microseismic cloud relative to horizontal wells 604, 606 and a vertical monitoring well 608. The microseismic cloud illustrated here includes a total of 5,200 seismic events spanning magnitudes from -2 to 1.5, with the majority of the events falling below 0.5 in magnitude, which is readily detectable by the fiber optic cables. The map view 602 illustrates that the microseismic cloud here shows a fracture orientation in the NE-SW direction with an extension of 1000 feet in the direction of SH max. Greater extension is observed towards the NE direction compared to the SW direction. The cross-sectional view 610 illustrates that the microseismic cloud here exhibits symmetric distribution 300 feet above and below the stimulated wells. This vertical distribution correlates with low-frequency strain rate data, suggesting fracture extension approximately 300-500 feet shallower than these wells.

[0044] FIG. 7 illustrates an example 700 of seismic data provided by a monitoring system, in accordance with examples described herein. The seismic data is acquired by fiber optic cables of the monitoring system during well stimulation activities. The seismic data illustrated in the example 700 correspond with a concentration of seismic events observed near the toe of a first horizontal well (e.g., horizontal well 604 of FIG. 6, horizontal well 306 of FIG. 3). The seismic data 702 received by the fiber optic cables installed in a second horizontal well (e.g., horizontal well 606 of FIG. 6, horizontal well 304 of FIG.3) and the seismic data 704 received by the fiber optic cables installed in the first horizontal well show near-zero P and S wave separation, which indicates the proximity of the seismic events to the first horizontal well and the second horizontal well. The seismic data 706 received by fiber optic cables installed in a vertical well (e.g., vertical monitoring well 608 of FIG.6, vertical monitoring well 302 of FIG.3) shows a P-wave that arrived nearly perpendicular to the well.

[0045] FIG. 8 illustrates an example 800 of seismic data provided by a monitoring system, in accordance with examples described herein. The seismic data is acquired by fiber optic cables of the monitoring system during well stimulation activities. The example 800 illustrates the seismic data as energy plots. In the first energy plot 802, an energy distribution 812 around a horizontal well 808 and a vertical well 810 demonstrates a first region of approximate microseismic event locations with a dot and an x marking areas of likely event locations based on magnitude. The first energy plot 802 is based on the seismic data acquired by a first fiber optic cable (e.g., a fiber optic cable in the horizontal well 808). In the second energy plot 804, an energy distribution 814 around the horizontal well 808 and the vertical well 810 demonstrates a second region of approximate microseismic event locations with a dot and an x marking areas of likely event locations based on magnitude. The second energy plot 804 is based on the seismic data acquired by a second fiber optic cable (e.g., a fiber optic cable in the vertical well 810). In the third energy plot 806, energy distributions 816, 818 illustrate the overlap between the first energy plot 802 and the second energy plot 804, providing approximate microseismic event locations based on the seismic data acquired by the first fiber optic cable and the second fiber optic cable. This refined location analysis constrains the event locations to two regions with a dot and an x marking areas of likely event locations based on magnitude.

[0046] FIG. 9 illustrates an example of seismic events detected by a monitoring system in a natural resource system, in accordance with examples described herein. The seismic events are detected using seismic data collected by fiber optic cables in the natural resource system. As illustrated in FIG. 9, a map view 902 and a cross-sectional view 910 illustrate microseismic event distributions during double stimulation (e.g., a second stimulation of the natural resource system). The map view 902 and the cross-sectional view 910 illustrate themicroseismic cloud relative to horizontal wells 904, 906 and a vertical monitoring well 908. Comparing the microseismic cloud illustrated here with, for example, the microseismic cloud illustrated in FIG.6, demonstrates an expansion towards the north of the well and expansion both above and below the horizontal well. This expansion may, for example, be attributed to reactivation of previously created factures from previous stimulation of the natural resource system.

[0047] FIG. 10 illustrates an example technique 1000 for monitoring seismic data, in accordance with examples described herein. The operations of the example technique 1000 are illustrative, and the sequence may be altered without departing from the scope of the present invention. For example, the example technique 1000 can be performed with additional or fewer operations. The operations of the example technique 1000 can be performed in sequence, in parallel, or in different orders. In some examples, different components of an example device or system that implements an example technique may perform operations at substantially the same time or in a specific sequence.

[0048] At 1002, the example technique 1000 installs fiber optic cables in a plurality of wells, wherein the plurality of wells comprises at least one vertical well and at least one horizontal well. The fiber optic cables may be installed, for example, in accordance with the details provided in FIGS. 2-4.

[0049] At 1004, the example technique 1000 acquires microseismic data from the fiber optic cables during stimulation of at least one well of the plurality of wells. The microseismic data may be acquired, for example, in accordance with the details provided in FIGS. 5-9.

[0050] At 1006, the example technique 1000 detects microseismic events from the microseismic data. The microseismic events may be detected, for example, in accordance with the details provided in FIGS. 6-9.

[0051] At 1008, the example technique 1000 determines locations of the microseismic events using the microseismic data. The locations may be determined, for example, in accordance with the details provided in FIGS.6-9.

[0052] FIG. 11 illustrates generally an example of a block diagram of a machine 1100 upon which any one or more of the techniques (e.g., methodologies) discussed herein may perform in accordance with some examples. In alternative examples, the machine 1100 may operate as a standalone device or may beconnected (e.g., networked) to other machines. In a networked deployment, the machine 1100 may operate in the capacity of a server machine, a client machine, or both in server-client network environments. In an example, the machine 1100 may act as a peer machine in peer-to-peer (P2P) (or other distributed) network environment. The machine 1100 may be a personal computer (PC), a tablet PC, a set-top box (STB), a personal digital assistant (PDA), a mobile telephone, a web appliance, a network router, switch or bridge, or any machine capable of executing instructions (sequential or otherwise) that specify actions to be taken by that machine. Further, while only a single machine is illustrated, the term “machine” shall also be taken to include any collection of machines that individually or jointly execute a set (or multiple sets) of instructions to perform any one or more of the methodologies discussed herein, such as cloud computing, software as a service (SaaS), other computer cluster configurations.

[0053] Examples, as described herein, may include, or may operate on, logic or a number of components, modules, or mechanisms. Modules are tangible entities (e.g., hardware) capable of performing specified operations when operating. A module includes hardware. In an example, the hardware may be specifically configured to carry out a specific operation (e.g., hardwired). In an example, the hardware may include configurable execution units (e.g., transistors, circuits, etc.) and a computer readable medium containing instructions, where the instructions configure the execution units to carry out a specific operation when in operation. The configuring may occur under the direction of the execution units or a loading mechanism. Accordingly, the execution units are communicatively coupled to the computer readable medium when the device is operating. In this example, the execution units may be a member of more than one module. For example, under operation, the execution units may be configured by a first set of instructions to implement a first module at one point in time and reconfigured by a second set of instructions to implement a second module.

[0054] Machine (e.g., computer system) 1100 may include a hardware processor 1102 (e.g., a central processing unit (CPU), a graphics processing unit (GPU), a hardware processor core, or any combination thereof), a main memory 1104 and a static memory 1106, some or all of which may communicate with each other via an interlink (e.g., bus) 1108. The machine 1100 may further include adisplay unit 1110, an alphanumeric input device 1112 (e.g., a keyboard), and a user interface (UI) navigation device 1114 (e.g., a mouse). In an example, the display unit 1110, alphanumeric input device 1112 and UI navigation device 1114 may be a touch screen display. The machine 1100 may additionally include a storage device (e.g., drive unit) 1116, a signal generation device 1118 (e.g., a speaker), a network interface device 1120, and one or more sensors 1121, such as a global positioning system (GPS) sensor, compass, accelerometer, or other sensor. The machine 1100 may include an output controller 1128, such as a serial (e.g., universal serial bus (USB), parallel, or other wired or wireless (e.g., infrared (IR), near field communication (NFC), etc.) connection to communicate or control one or more peripheral devices (e.g., a printer, card reader, etc.).

[0055] The storage device 1116 may include a machine readable medium 1122 that is non-transitory on which is stored one or more sets of data structures or instructions 1124 (e.g., software) embodying or utilized by any one or more of the techniques or functions described herein. The instructions 1124 may also reside, completely or at least partially, within the main memory 1104, within static memory 1106, or within the hardware processor 1102 during execution thereof by the machine 1100. In an example, one or any combination of the hardware processor 1102, the main memory 1104, the static memory 1106, or the storage device 1116 may constitute machine readable media.

[0056] While the machine readable medium 1122 is illustrated as a single medium, the term “machine readable medium” may include a single medium or multiple media (e.g., a centralized or distributed database, or associated caches and servers) configured to store the one or more instructions 1124.

[0057] The term “machine readable medium” may include any medium that is capable of storing, encoding, or carrying instructions for execution by the machine 1100 and that cause the machine 1100 to perform any one or more of the techniques of the present disclosure, or that is capable of storing, encoding or carrying data structures used by or associated with such instructions. Non- limiting machine-readable medium examples may include solid-state memories, and optical and magnetic media. Specific examples of machine-readable media may include: non-volatile memory, such as semiconductor memory devices (e.g., Electrically Programmable Read-Only Memory (EPROM), ElectricallyErasable Programmable Read-Only Memory (EEPROM)) and flash memory devices; magnetic disks, such as internal hard disks and removable disks; magneto-optical disks; and CD-ROM and DVD-ROM disks.

[0058] The instructions 1124 may further be transmitted or received over a communications network 1126 using a transmission medium via the network interface device 1120 utilizing any one of a number of transfer protocols (e.g., frame relay, internet protocol (IP), transmission control protocol (TCP), user datagram protocol (UDP), hypertext transfer protocol (HTTP), etc.). Example communication networks may include a local area network (LAN), a wide area network (WAN), a packet data network (e.g., the Internet), mobile telephone networks (e.g., cellular networks), and wireless data networks (e.g., Institute of Electrical and Electronics Engineers (IEEE) 802.11 family of standards known as Wi-Fi®, IEEE 802.16 family of standards known as WiMax®), IEEE 802.15.4 family of standards, peer-to-peer (P2P) networks, among others. In an example, the network interface device 1120 may include one or more physical jacks (e.g., Ethernet, coaxial, or phone jacks) or one or more antennas to connect to the communications network 1126. In an example, the network interface device 1120 may include a plurality of antennas to wirelessly communicate using at least one of single-input multiple-output (SIMO), multiple-input multiple-output (MIMO), or multiple-input single-output (MISO) techniques. The term “transmission medium” shall be taken to include any intangible medium that is capable of storing, encoding or carrying instructions for execution by the machine 1100, and includes digital or analog communications signals or other intangible medium to facilitate communication of such software. GLOSSARY

[0059] Generally, the term “about” and the symbol “~” as used herein unless stated otherwise is meant to encompass a variance or range of ±10%, the experimental or instrument error associated with obtaining the stated value, and preferably the larger of these.

[0060] As used herein, unless specified otherwise, the terms “formation”, “reservoir”, “pay zone”, and similar terms are to be given their broadest possible meanings, and include all locations, areas, and geological features within theearth that contain, may contain, or are believed to contain, a desired resource (e.g., geothermal heat, hydrocarbons, etc.).

[0061] As used herein, unless specified otherwise, the terms “field”, “oil field”, “geothermal field”, and similar terms are to be given their broadest possible meanings, and include any area of land, sea floor, or water that is loosely or directly associated with a formation, and more particularly, with a resource containing formation. Thus, a field may have one or more exploratory and producing wells associated with it. A field may have one or more governmental body or private resource leases associated with it. A field may be directly associated with a resource containing formation.

[0062] As used herein, unless specified otherwise, the terms “geothermal”, “geothermal well”, “geothermal resource”, “geothermal energy”, and similar terms are to be given their broadest possible meanings, and include systems and operations, including wells, that recover or utilize the heat energy that is contained within the earth. Such systems and operations include enhanced geothermal well, engineered geothermal wells, binary cycle power plants, dry steam power plants, flash steam power plants, open looped systems, and closed loop systems.

[0063] As used herein, unless specified otherwise, the term “earth” should be given its broadest possible meaning, and includes, the ground, all natural materials, such as rocks, and artificial materials, such as concrete, that are or may be found in the ground, including without limitation rock layer formations, such as, granite, basalt, sandstone, dolomite, sand, salt, limestone, rhyolite, quartzite and shale rock.

[0064] As used herein, unless specified otherwise, the term “borehole” should be given it broadest possible meaning and includes any opening that is created in a material, a work piece, a surface, the earth, a structure (e.g., building, protected military installation, nuclear plant, offshore platform, or ship), or in a structure in the ground, (e.g., foundation, roadway, airstrip, cave or subterranean structure) that is substantially longer than it is wide, such as a well, a well bore, a well hole, a micro hole, a slimhole, a perforation, or other term commonly used to define these types of long narrow passages. Wells would further include exploratory, production, abandoned, reentered, reworked, and injection wells. Although boreholes are generally oriented substantially vertically, they may alsobe oriented on an angle from vertical, to and including horizontal. Thus, using a vertical line, based upon a level as a reference point, a borehole can have orientations ranging from 0° i.e., vertical, to 90°, i.e., horizontal and greater than 90° e.g., such as a heel and toe and combinations of these such as for example “U” and “Y” shapes. Boreholes may further have segments or sections that have different orientations, they may have straight sections and arcuate sections and combinations thereof; and for example, may be of the shapes commonly found when directional drilling is employed. Thus, as used herein unless expressly provided otherwise, the “bottom” of a borehole, the “bottom surface” of the borehole and similar terms refer to the end of the borehole, i.e., that portion of the borehole furthest along the path of the borehole from the borehole's opening, the surface of the earth, or the borehole's beginning. The terms “side” and “wall” of a borehole should to be given their broadest possible meaning and include the longitudinal surfaces of the borehole, whether or not casing or a liner is present, as such, these terms would include the sides of an open borehole or the sides of the casing that has been positioned within a borehole. Boreholes may be made up of a single passage, multiple passages, connected passages and combinations thereof, in a situation where multiple boreholes are connected or interconnected each borehole would have a borehole bottom. Boreholes may be formed in the sea floor, under bodies of water, on land, in ice formations, or in other locations and settings.

[0065] As used herein, phrases of the form “at least one of an A, a B, or a C”, “at least one of A, B, or C”, “at least one of A, B, and C”, and similar phrases, should be interpreted to select at least one from the group that comprises A, B, and C. ^ Unless explicitly stated otherwise in connection with a particular instance, this manner of phrasing does not mean “at least one of A, at least one of B, and at least one of C.” ^ As used herein, the example “at least one of an A, a B, or a C” would cover any of the following selections: {A}, {B}, {C}, {A, B}, {A, C}, {B, C}, and {A, B, C}.

[0066] Unless the context clearly requires otherwise, throughout the description and the claims, the words “comprise,” “comprising,” and the like are to be construed in an inclusive sense, as opposed to an exclusive or exhaustive sense, i.e., in the sense of “including, but not limited to.” As used herein, the terms “connected,” “coupled,” or any variant thereof means any connection orcoupling, either direct or indirect, between two or more elements; the coupling or connection between the elements can be physical, logical, or a combination thereof. Additionally, the words “herein,” “above,” “below,” and words of similar import, when used in this application, refer to this application as a whole and not to any particular portions of this application. Where the context permits, words using the singular or plural number may also include the plural or singular number, respectively. The word “or” in reference to a list of two or more items, covers all of the following interpretations of the word: any one of the items in the list, all of the items in the list, and any combination of the items in the list. Likewise, the term “and / or” in reference to a list of two or more items, covers all of the following interpretations of the word: any one of the items in the list, all of the items in the list, and any combination of the items in the list. EXAMPLES

[0067] In view of the above-described implementations of subject matter this application discloses the following list of examples, wherein one feature of an example in isolation or more than one feature of an example, taken in combination and, optionally, in combination with one or more features of one or more further examples are further examples also falling within the disclosure of this application.

[0068] Example 1 is a method for monitoring microseismic activity in a geothermal well system, comprising: installing fiber optic cables in a plurality of wells, wherein the plurality of wells comprises at least one vertical well and at least one horizontal well; acquiring microseismic data from the fiber optic cables during stimulation of at least one well of the plurality of wells; detecting microseismic events from the microseismic data; and determining locations of the microseismic events using the microseismic data.

[0069] In Example 2, the subject matter of Example 1 comprises wherein installing fiber optic cables in the plurality of wells comprises: installing permanent fiber optic cables behind casing in the plurality of wells.

[0070] In Example 3, the subject matter of Examples 1 – 2 comprises wherein the microseismic data comprises distributed acoustic sensing (DAS) data.

[0071] In Example 4, the subject matter of Examples 1 – 3 comprises wherein detecting microseismic events from the microseismic data is based on a Short- Term Average / Long-Term Average based triggering method.

[0072] In Example 5, the subject matter of Examples 1 – 4 comprises wherein determining the locations of the microseismic events comprises: estimating event depth based on the microseismic data from at least one vertical fiber optic cable of the at least one vertical well; and estimating aerial location based on the microseismic data from at least one horizontal fiber optic cable of the at least one horizontal well.

[0073] In Example 6, the subject matter of Examples 1 – 5 comprises wherein determining the locations of the microseismic events comprises: performing a coarse grid search to identify approximate locations of the microseismic events; and performing a refined grid search to determine the locations of the microseismic events based on the approximate locations.

[0074] In Example 7, the subject matter of Examples 1 – 6 comprises determining fracture geometry parameters comprising fracture orientation, fracture length, and fracture height based on the microseismic data; and determining microseismic diffusion rates based on the microseismic data.

[0075] In Example 8, the subject matter of Examples 1 – 7 comprises collecting low-frequency strain rate data from the fiber optic cables; and correlating the microseismic data with the low-frequency strain rate data to determine fracture extension.

[0076] In Example 9, the subject matter of Examples 1 – 8 comprises performing a crossflow test within the plurality of wells; monitoring seismicity during the crossflow test using the fiber optic cables; and verifying that seismic events remain confined within a stimulated rock volume based on the seismicity.

[0077] In Example 10, the subject matter of Examples 1 – 9 comprises the fiber optic cables are operable at a temperature of 200°C; and the fiber optic cables comprise at least two single-mode fibers and two multi-mode fibers.

[0078] Example 11 is a system for monitoring microseismic activity in a plurality of wells comprising at least one vertical well and at least one horizontal well, the system comprising: fiber optic cables installed behind casing of the plurality of wells; and a processor configured to perform operations comprising: acquiring microseismic data from the fiber optic cables during stimulation of atleast one well of the plurality of wells; detecting microseismic events from the microseismic data; and determining locations of the microseismic events using the microseismic data.

[0079] In Example 12, the subject matter of Example 11 comprises wherein: the fiber optic cables are operable at a temperature of 200°C; and the fiber optic cables simultaneously collect microseismic data, strain rate data, and temperature data.

[0080] In Example 13, the subject matter of Examples 11 – 12 comprises wherein the operations further comprise: monitoring fracture geometry parameters comprising fracture orientation, fracture length, and fracture height; and correlating microseismic event distribution with low-frequency strain rate data to determine fracture extension.

[0081] In Example 14, the subject matter of Examples 11 – 13 comprises surface seismic sensors installed on hard rock formation outcrops.

[0082] Example 15 is one or more non-transitory computer-readable media storing computer-executable instructions that, when executed by a computing system, cause the computing system to perform operations comprising: acquiring microseismic data from fiber optic cables during stimulation of at least one well of a plurality of wells; detecting microseismic events from the microseismic data; and determining locations of the microseismic events using the microseismic data.

[0083] The present invention may be embodied in other forms than those specifically disclosed herein without departing from the spirit or essential characteristics of the present invention. The described examples are to be considered in all respects only as illustrative and not restrictive.

[0084] The various examples of systems, compositions, articles, uses, applications, equipment, methods, activities, and operations set forth in this specification may be used for various other fields and for various other activities, uses and examples. Additionally, these examples may be used with: existing systems, compositions, articles, uses, applications, equipment, methods, activities, and operations; may be used with systems, compositions, articles, uses, applications, equipment, methods, activities, and operations that may be developed in the future; and with such systems, compositions, articles, uses, applications, equipment, methods, activities, and operations that may bemodified, in-part, based on the teachings of this specification. Further, the various examples set forth in this specification may be used with each other, in whole or in part, and in different and various combinations. Thus, for example, the configurations provided in the various examples of this specification may be used with each other; and the scope of protection afforded the present inventions should not be limited to a particular example, configuration or arrangement that is set forth in a particular example, or in an example in a particular figure.

Claims

CLAIMS What is claimed is:

1. A method for monitoring microseismic activity in a geothermal well system, comprising: installing fiber optic cables in a plurality of wells, wherein the plurality of wells comprises at least one vertical well and at least one horizontal well; acquiring microseismic data from the fiber optic cables during stimulation of at least one well of the plurality of wells; detecting microseismic events from the microseismic data; and determining locations of the microseismic events using the microseismic data.

2. The method of claim 1, wherein installing fiber optic cables in the plurality of wells comprises: installing permanent fiber optic cables behind casing in the plurality of wells.

3. The method of claim 1, wherein the microseismic data comprises distributed acoustic sensing (DAS) data.

4. The method of claim 1, wherein detecting microseismic events from the microseismic data is based on a Short-Term Average / Long-Term Average based triggering method.

5. The method of claim 1, wherein determining the locations of the microseismic events comprises: estimating event depth based on the microseismic data from at least one vertical fiber optic cable of the at least one vertical well; and estimating aerial location based on the microseismic data from at least one horizontal fiber optic cable of the at least one horizontal well.

6. The method of claim 1, wherein determining the locations of the microseismic events comprises:performing a coarse grid search to identify approximate locations of the microseismic events; and performing a refined grid search to determine the locations of the microseismic events based on the approximate locations.

7. The method of claim 1, further comprising: determining fracture geometry parameters comprising fracture orientation, fracture length, and fracture height based on the microseismic data; and determining microseismic diffusion rates based on the microseismic data.

8. The method of claim 1, further comprising: collecting low-frequency strain rate data from the fiber optic cables; and correlating the microseismic data with the low-frequency strain rate data to determine fracture extension.

9. The method of claim 1, further comprising: performing a crossflow test within the plurality of wells; monitoring seismicity during the crossflow test using the fiber optic cables; and verifying that seismic events remain confined within a stimulated rock volume based on the seismicity.

10. The method of claim 1, wherein: the fiber optic cables are operable at a temperature of 200°C; and the fiber optic cables comprise at least two single-mode fibers and two multi-mode fibers.

11. A system for monitoring microseismic activity in a plurality of wells comprising at least one vertical well and at least one horizontal well, the system comprising: fiber optic cables installed behind casing of the plurality of wells; and a processor configured to perform operations comprising:acquiring microseismic data from the fiber optic cables during stimulation of at least one well of the plurality of wells; detecting microseismic events from the microseismic data; and determining locations of the microseismic events using the microseismic data.

12. The system of claim 11, wherein: the fiber optic cables are operable at a temperature of 200°C; and the fiber optic cables simultaneously collect microseismic data, strain rate data, and temperature data.

13. The system of claim 11, wherein the operations further comprise: monitoring fracture geometry parameters comprising fracture orientation, fracture length, and fracture height; and correlating microseismic event distribution with low-frequency strain rate data to determine fracture extension.

14. The system of claim 11, further comprising: surface seismic sensors installed on hard rock formation outcrops.

15. One or more non-transitory computer-readable media storing computer- executable instructions that, when executed by a computing system, cause the computing system to perform operations comprising: acquiring microseismic data from fiber optic cables during stimulation of at least one well of a plurality of wells; detecting microseismic events from the microseismic data; and determining locations of the microseismic events using the microseismic data.

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