Horizontal geothermal drilling and multistage hydraulic stimulation treatment

Abstract

Systems and techniques may be used for horizontal geothermal drilling and multistage hydraulic stimulation treatment. An example technique may include receiving in-well fiber optics data related to stimulation treatment effectiveness at a horizontal well comprising a set of hydraulically conductive fractures. The example technique may include determining a well condition of the horizontal well based on the in-well fiber optics data.

Description

HORIZONTAL GEOTHERMAL DRILLING AND MULTISTAGE HYDRAULIC STIMULATION TREATMENTSTATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0001] This invention was made with government support under DE-EE0007080 and DE-EE0008486 by the U.S. Department of Energy. The government has certain rights in this invention.PRIORITY CLAIM

[0002] This application claims the benefit of U.S. Provisional Application No. 63 / 441,752, filed on January 27, 2023, which is hereby incorporated by reference in its entirety.BACKGROUND

[0003] Geothermal energy systems typically use an injection well to introduce a cool injection fluid from the surface into a geothermal energy reservoir thousands of feet below ground. The geothermal energy reservoir is a formation such as a heated rock formation. As the injected fluid travels through the geothermal reservoir, the fluid absorbs heat increasing its temperature or enthalpy. One or more production wells are also disposed in the formation and are offset from the injection well so that the heated fluid may be pumped up from the formation to the surface where the heat may be extracted from the heated fluid to provide useable energy, often in the form of electricity. For example, a generator such as a steam turbine, Organic Rankine Cycle turbine, or other turbine may be used to convert the thermal energy entrained in the geothermal fluid into electricity. When geothermal power is generated using an Organic Rankine Cycle power plant, geothermal is a clean, renewable, zeroemission energy source.BRIEF DESCRIPTION OF THE DRAWINGS

[0004] In the drawings, which are not necessarily drawn to scale, like numerals may describe similar components in different views. Like numerals having different letter suffixes may represent different instances of similar components. The drawings illustrate generally, by way of example, but not by way of limitation, various embodiments discussed in the present document.

[0005] FIG. 1 illustrates a treatment plot, a distributed acoustic sensing (DAS) waterfall plot, and a distributed temperature sensing (DTS) waterfall plot in accordance with some examples.

[0006] FIG. 2 illustrates the histogram of the estimated fluid volume attributed to each perforation cluster in accordance with some examples.

[0007] FIG. 3 illustrates simulation results showing bottomhole pressure and bottomhole temperature during a multistage stimulation treatment in accordance with some examples.

[0008] FIG. 4 illustrates treating plots and DTS temperature trace at the Stage 16 plug location recorded while treating Stages 15 and 16 in accordance with some examples.

[0009] FIGS. 5A-5B illustrates example microseismic events in accordance with some examples.

[0010] FIG. 6 illustrates a treatment plot and low-frequency DAS crosswell strain response in accordance with some examples.

[0011] FIG. 7 displays the recorded cross-well strain change captured by the fiber cable installed in a monitoring well in accordance with some examples.

[0012] FIG. 8 illustrates the modeled cross-well strain change in accordance with some examples.

[0013] FIG. 9 illustrates a flowchart showing a technique for horizontal geothermal drilling and multistage hydraulic stimulation treatment in accordance with some examples.DETAILED DESCRIPTION

[0014] Firm, zero-carbon, dispatchable resources are key to unlocking a fully decarbonized electricity sector. Geothermal power can play that role, but in order to contribute a significant fraction of the energy mix geothermal projects must be deployed with the speed and scale that the industry has not yet achieved. Leveraging technology innovations from the unconventional oil and gas industry provides a pathway to unlocking new geologic resources and improving project economics in a way that could enable geothermal developers to mimic the rapid scale-up observed in shale development over the past two decades.

[0015] A horizontal well design results in geothermal systems where injection and production wells are connected in the subsurface by a set of hydraulically conductive fractures. These fractures act as flow pathways between the wells and provide sufficient contact area with the geothermal reservoir to enable sustained heat recovery over the life of the system.

[0016] Horizontal drilling has the potential to improve geothermal project economics significantly by providing greater access to the target reservoir volume, more consistent flow rates, more even flow distribution throughout the reservoir volume, and greater total heat transfer surface area. In addition, horizontal well designs offer many engineering design decisions that can be optimized to improve reservoir performance, including lateral length, offset well spacing, size of the stimulated reservoir volume, and fracture spacing along the wells. Horizontal well designs, stimulation treatment programs, and reservoir management strategies can then be tailored for a given geologic resource and therefore enables a broader range of geologies to be developed than is possible using conventional geothermal drilling technology.

[0017] In field-scale development programs, horizontal drilling can result in a significant reduction in surface land use because multiple wells can be drilled from a single pad location. Drilling many wells from the same pad can enable cascading cost savings opportunities, such as minimizing in-field rig moves, reducing drilling risk by drilling closely spaced vertical well sections, co-locating surface facilities infrastructure, and minimizing pipeline costs.

[0018] Perhaps most importantly, the advantages of horizontal drilling described here make it possible to replicate the dramatic learning curve cost-reductions that have been observed in the unconventional oil and gas sector over the last two decades. Drilling many wells in a condensed area allows for geologic, technical and experience learning curves to be applied as a development project progresses, improving project economics over time.

[0019] The overall stratigraphic framework at Blue Mountain includes Miocene to present basin-fill deposits overlying Mesozoic phyllite. The phyllite is intruded by multiple phases of igneous dikes / sills of likely Mesozoic and Tertiary ages. The range- front fault on the SW side of the Blue Mountain forms a prominent topographic break. On the NW side of Blue Mountain, silicified fault breccia is locally exposed in isolated outcrops surrounded by alluvium along the westernmost exposures of the surface trace of this fault. As previously noted and in later reports, the westernmost exposure of this fault zone is silicified, and the silicification was interpreted to be relict. Kinematic data collected from fault surfaces along the western half of the range-front fault indicate dextral-oblique motion.

[0020] Based on the map pattern of the faults and kinematic data, the Blue Mountain geothermal system is associated with a displacement transfer zone. In this structural model, the range-front along the SW side of the range is dextral-normal. This fault dies out into the basin west of the nose of the range and dextral shear is transferred to NE-striking normal faults that accommodate NW-SE extension in the form of pure dip-slip motion along the NW side of the Blue Mountain range. In this type of model, deep circulation would most likely be controlled by the N to NE- striking normal faults, near where they intersect the NW-striking dextral-normal fault system.

[0021] As is the case in most extensional settings, the wells located furthest out in the basin have the deepest depth to basement, especially 13-11 and 41-27 which are idle wells on the northern and southern margins of the field. The rest of the infield and nearfield wells show less variance in depth to basement as a function of distance to the range-front because faulting within the field is controlling the lithologic contacts. Stratigraphic control from the well data shows that the basementprogressively steps down to the NW, with the contact within each fault block gently dipping back towards the range front. The NW, N, and NE -striking faults which drop basement down in the core of the field are truncated to the south by the SW range front fault, which strikes from SE to NW across the SW side of Blue Mountain and continues obscured under basin fill to the west. On the north end of the field, these core faults merge into the NW range front of Blue Mountain.

[0022] South of the geothermal upflow and outflow zones of the primary hydrothermal system at Blue Mountain, there have been several wells drilled previously (86-22, 41-27, and 34-23) which exhibit relatively conductive temperature conditions and lack deep permeability or connectivity to the rest of the wellfield. This permeability boundary along the south side of the reservoir lies just south of well 61-22 and has been interpreted to be associated with the down-dip projection of the southwest range-front fault.

[0023] The horizontal well designs were driven by one or more of the following factors: a) the requirement of a 7” production casing string to enable commercial flow rates, b) the requirement of permanent fiber optic cable installation cemented behind the production casing for improved reservoir and wellbore diagnostics, c) a conservative casing program that would be robust against known and unknown geologic hazards in this first of a kind project, and d) the local state of stress, and e) the three-dimensional temperature distribution in the reservoir.

[0024] The trajectory of a Production Well 34-22 was determined using a methodology that combined multiple datasets, including a three-dimensional geologic model, stress field data from image log interpretations, temperature distribution data, as well as information on the geometry of the stimulated reservoir volume, such as microseismic data and low-frequency distributed acoustic sensing data. Proppant was detected while drilling the 34-22 wellbore, confirming the well path intersected the stimulated reservoir volume.

[0025] A 16-stage plug-and-perf hydraulic stimulation treatment was performed on Injection Well 34A-22 over a six-day period from July 21 - July 26, 2022. The plug-and-perf stimulation treatment method, which is now the most commonstimulation method used in unconventional oil and gas wells, involves the following steps for a typical stage:

[0026] Rig up a wireline toolstring with a “flow-through” bridge plug and several perforation charges.

[0027] Lower the wireline toolstring into the well. The toolstring is conveyed by wireline until reaching the curve section of the well.

[0028] Pump trucks are engaged and the toolstring is pumped down the lateral by injecting into the well at rates of approximately 10 bpm until reaching the target location for the bridge plug.

[0029] The bridge plug setting tool is fired, and the plug is set a prespecified location along the lateral.

[0030] The wireline toolstring is pulled uphole until reaching the prespecified location for the deepest perforation cluster and the perforation charges are fired. This step is repeated for all perforation clusters in the given stage.

[0031] Wireline is pulled out of hole.

[0032] A ball is dropped in the wellhead and pumped downhole. A pressure spike on surface signals that the ball has seated in the bridge plug. The current stage is now isolated hydraulically from the previous stage.

[0033] The treatment is then pumped as designed, typically beginning with an acid spear of approximately 1000 gal of 15% HC1, followed by a pad of clean fluid, and then gradually increasing proppant concentration throughout the remainder of the stage. At the end of the stage, a sweep of clean fluid is pumped to flush the wellbore from any remaining proppant.

[0034] And, the pumps are shut down and the instantaneous shut-in pressure (ISIP) is recorded.

[0035] Each stage had roughly the same length of approximately 150 ft. All stages were planned with a similar perforation cluster design, with 6 clusters per stage and 6 perforation shots per cluster, except for Stages 12 and 13, which each had 9 clusters per stage and variable shots per cluster. The perforation clusters were designed with a limited entry style design, targeting approximately 1,500 psi of perforation friction.

[0036] The treatment design called for pumping a total of approximately 17,000 bbl of fluid and 540,000 lbs of proppant in each stage. The target injection rate was 100 bpm. The stimulation fluid was a slickwater treatment design with a low- concentration friction reducer additive. The proppant was a mixture of 100 mesh and 40 / 70 mesh silica sand, pumped at concentrations ranging from 0.25 to 1.5 ppg. Each stage lasted approximately 3 hours.

[0037] FIG. 1 illustrates a treatment plot showing surface injection pressure, injection rate, and proppant concentration, a DAS waterfall plot showing acoustic signal and location of perforation clusters from an active stage and previous stage, and a DTS waterfall plot showing temperature variations along the well throughout a duration of an active stage.

[0038] Stimulation treatment effectiveness may be evaluated using in-well fiber optic sensing diagnostics. The treatment plot 102 for a typical stage is shown in FIG. 1. In- well fiber optics data may be used to observe downhole behavior in realtime before, during, and after each stage. This fiber optic data provides useful information on the stimulation treatment effectiveness and the downhole conditions that various tools are exposed to.

[0039] The in-well DAS data in chart 104 may be used to verify whether fracture initiation occurred at each perforation cluster as well as the flow allocation across all clusters in the stage. In this example, we observed that all six perforation clusters broke down and received flow for the full duration of the stage. Taking the DAS amplitude signal as a proxy for flow rate at each perforation cluster, we observed that clusters 2, 3, and 5 were the most active, however all clusters took flow and the overall flow uniformity index was calculated. The relatively low levels of acoustic activity downstream of the bridge plug indicate that good stage isolation was achieved.

[0040] During the stimulation treatment, the DTS data in chart 106 may be used to determine stage isolation and to determine if any leakage is occurring into the previous stage, either around the plug or behind the casing. In this example, some cooling was observed downstream of the plug in the first half of the stage, but toward the middle of the stage a clear warmback signal is observed. The relativelysmall amount of cooling early in the stage may be caused by near-well fracture communication as fracture initiation occurred, as opposed to a leaky plug.

[0041] In- well fiber optic sensing data was recorded for 13 out of the 16 stages.Upon analyzing the fiber data for all stages, fracture breakdown and initiation occurred at 100% of the perforation clusters, regardless of the lithology that the perforation clusters were located in.

[0042] FIG. 2 illustrates a histogram 202 of an estimated total fluid volume allocated to each perforation cluster across the entire lateral. Fluid volumes and cluster allocation may be estimated using the DAS acoustic intensity signal. The DAS data may indicate that all clusters initiated and actively received flow during the stimulation treatment.

[0043] FIG. 2 illustrates the histogram 202 of the estimated fluid volume attributed to each perforation cluster, and although there is some spread, all clusters took flow during the stimulation treatment. The stages with 9 clusters also included relatively good flow distribution, verifying that extreme limited entry completions are likely a viable path towards meaningful cost reductions in future drilling campaigns. In an example, no evidence of a bridge plug failure was found, indicating that the bridge plugs used in this project were rated to sufficient temperature and differential pressure ratings for the downhole conditions that were experienced.

[0044] FIG. 3 illustrates simulation results showing bottomhole pressure and bottomhole temperature during a multistage stimulation treatment. Wellbore temperature cools down significantly while pumping at rates of 100 bpm, approaching the surface injection temperature. While the well is shut-in between stages, the well warms back up, but remains well below the static formation temperature. During a “worst-case” scenario with a long shut-in period, the wellbore temperature remains below 300 °F. These results were used to inform bridge plug selection for the stimulation treatment program.

[0045] Zonal isolation tool and technology development has been a focus area for the geothermal industry over the last several years. For multistage stimulation treatments in horizontal wells at geothermal conditions, there are several aspects ofthe operation that require careful attention. In this case, the tools must be capable of running in 7” 35# casing (ID = 6.004”). In addition, the maximum recorded bottomhole temperature was 374 °F. Previously, it is believed that ball-drop flow- through bridge plugs had never been run in a horizontal well with a 7” production casing size or at these high temperature conditions.

[0046] A modeling study may be used to characterize anticipated downhole temperature conditions to inform operational plans. A numerical reservoir simulator capable of modeling fluid flow, fracture propagation, and heat transfer with a fully coupled wellbore model that included wellbore heat transfer may be used. A horizontal well scenario representative of Injection Well 34A-22 may be used. A formation temperature of 400 °F, fluid injected at a rate of 100 bpm for 2 hours, and an injected fluid temperature of 85 °F may be used. Two stimulation treatment stages near the toe of the lateral may be used. The inter-stage duration between Stages 1 and 2 may be 3 hours. In addition, a 12-hour warmback period may be modeled to mimic a scenario where issues with the wireline assembly resulted in a long delay before pumping the next stage. Because the first two stages are near the toe of the well and a relatively static formation temperature was assumed, this is conservative scenario in terms of the warm back that may be expected. The relevant model properties are listed in Table 1.Table 1. Model properties used in the zonal isolation plug warmback analysis.Property ValueStatic Formation Temp. 400 °FInjection Fluid Temp. 85 °FTreating Rate 100 bpmStage Duration 2 hoursTypical Inter-stage 3 hoursDurationLong Inter-stage 12 hoursDuration

[0047] In FIG. 3, results of the numerical simulation are shown. During injection while treating at a rate of 100 bpm, the wellbore temperature dropped to approximately 90 °F. Following shut-in, the wellbore warmed back rapidly withinthe first hour but then began to warm back more slowly. At the end of the first shut- in period, the wellbore had warmed back to a maximum temperature of about 265 °F. During the next stage, the wellbore again cooled down to about 90 °F. At the end of the 12-hour shut-in period, the wellbore had heated back up to approximately 300 °F. Significant wellbore cooldown thus may be expected to occur during a field trial due to high-rate injection.

[0048] FIG. 4 illustrates treating plots 402 and DTS temperature trace at the Stage 16 plug location 404 recorded while treating Stages 15 and 16.

[0049] A stimulation field trial may be designed to include a test of three different zonal isolation bridge plug designs in order to better understand their performance. Two example bridge plug designs may be used, each rated to downhole temperatures of 300 - 350 °F. A high-temperature ball-drop flow-through bridge plug may be fabricated that meets the 7” casing requirements and is rated up to 450 °F. The technical specifications for the three types of plugs trialed in this project are shown in Table 2.Table 2. Technical specifications for the three zonal isolation bridge plugs that were used in the field trial.

[0050] Due to its slightly higher temperature rating and sturdier fixture material, Plug B was selected in Stages 1 - 6 near the toe of the well. The composite plug (Plug A) was run in Stages 7 - 15. The high-temperature aluminum plug (Plug C) was run on Stage 16 (the final stage).

[0051] Permanent fiber optic cable may be used to record continuous DTS measurements, allowing for monitoring temperature along the lateral throughout the stimulation treatment. In general, no evidence for plug failure on any stage based on downhole fiber optic data or surface pressure responses was found for the trial.

[0052] To further understand the conditions that the plugs were actually exposed to, the DTS measurements may be analyzed in greater detail.

[0053] In FIG. 4, the treatment plots 402 and the DTS temperature trace at the Stage 16 plug location (MD = 8,181 ft) 404 over the duration of Stages 15 and 16 are shown. The static formation temperature at this location was 370 °F based on the equilibrated temperature profile measured after drilling the well and prior to the stimulation treatment. By the end of Stage 15, the wellbore had cooled down to approximately 100 °F. In between stages, the wellbore warmed back, however, the maximum temperature observed prior to beginning pumping operations on Stage 16 was only 200 °F, significantly below the rated temperature of any of the plugs trialed in this project.

[0054] In FIG. 4, the temperature traces at the plug locations for several representative stages are shown. We observed that the Stage 1 plug was subjected to the highest downhole temperature conditions, and all subsequent stages tended to be exposed to lower maximum temperatures. The Stage 1 plug experienced temperatures approaching 300 °F, having only been cooled down by relatively low- volume and low-rate injection while conveying the wireline assembly via pumpdown operations. However, even that minor amount of injection was sufficient to cool the wellbore below the temperature rating of Plug A, the lowest rated plug that was trialed. Subsequent stages are generally exposed to lower temperatures because of the remnant cooling effects of prior stages.

[0055] In this case, the modeling forecasts were able to predict the downhole temperature conditions during the stimulation treatment accurately. Based on realtime downhole measurements, it was confirmed that bridge plugs do not need to be rated to the formation temperature because of the extreme cooling that occurs during wireline pumpdown and stimulation operations. In higher temperature formations, the rate of warmback in between stages will occur faster.

[0056] The temperature that the bridge plug was exposed to never exceeded 200 °F, well below its rated temperature limit. The results of this field trial indicate that it is possible to rely on significant amounts of wellbore cooldown due to wireline pumpdown operations and high-rate injection during the stimulation treatment.

[0057] FIGS. 5A-5B illustrates example microseismic events, for example on a vertical fiber 502 and on a horizontal fiber 504. In FIG. 5A, he apex of the S-wave can be used to infer the vertical depth of the microseismic event. The P-wave is a weak event further weakened at the peak due to the broad side sensitivity of the fiber. A converted S to P wave is detected for this event as evident at an approximate depth of 1500 m measured depth (MD). In FIG. 5B, the peak at 3260 m MD can be used to determine the location and distance of the event from the fiber in the azimuth direction. The noise band from 3170-3190 m corresponds to the stimulation activity for the stage.

[0058] The stimulation of Injection Well 34A-22 produced a significant number of microseismic events, which were detected with a favorable signal-to-noise ratio on multiple permanent fiber optic cables. A total of 5,200 events were observed on the vertical monitoring well. While the range of magnitudes varied from -2 to 1.5, the majority of events were below 0.5 and could be confidently detected on the fiber. A subset of the 5,200 events identified on the vertical fiber was also detected on the horizontal fiber, and the distribution of these events is shown in FIGS. 5A- 5B. The merged data from the vertical and horizontal fibers significantly improves the confidence of the event locations. However, the measurements of axial strain along the fibers imply that there is inherent uncertainty in the event location, particularly in the horizontal directions.

[0059] The azimuth of the individual stage events further confirms the stress orientation in the NE-SW direction identified from multiple sources across the Blue Mountain field. There appears to be a slight rotation of the microseismic (MS) cloud towards a more N-S orientation in the later stages near the heel. The event cloud extends approximately 1000 ft in the direction of SHmax, with more extension observed towards the NE compared to the SW. It is possible that the events extend symmetrically around the well, but events to the south are further away from the vertical well and hence are more attenuated. There is a symmetric distribution of the microseismic events in the vertical direction, with events extending approximately 300 ft above and below the stimulated well. The microseismic events can also be identified as stripes in the low-frequency strain rate data, and there is a goodcorrelation between the height of the microseismic events and the extension observed (in red) in the low-frequency strain rate data, suggesting that the fractures are extending about 300-500 ft shallower than the treatment well. The lack of fiber below the horizontal well prevents similar conclusions from being reached deeper to the well, but the microseismic data indicates that the fractures did extend 300 ft deeper.

[0060] The results presented here demonstrate that fiber-based multi-well distributed acoustic sensing (DAS) microseismic for geothermal fields has been successfully realized. Fiber based microseismic event locations can inform importance fracture geometry parameters like fracture orientations, fracture length and height, and the fracture propagation rate. The absence of reliable three- component borehole tools that can operate at temperatures above 400 °F further highlights the importance of fiber-optic-based microseismic measurements.

[0061] FIG. 6 illustrates a treatment plot 602 and low-frequency DAS crosswell strain response 604. Distributed acoustic sensing records strain changes along the axial axis of a fiber cable in a wide range of frequencies from mHz to several kHz. The low-frequency part of the data (<0.05 Hz), or so-called LF-DAS, is commonly used during hydraulic stimulations to evaluate cross-well strain changes in offset horizontal wells or vertical wells by interpreting the elastic stresses and strains that are induced by fracture propagation. In vertical monitoring wells, LF-DAS captures the change in the vertical component of the strain tensor. FIG. 7 displays the recorded cross-well strain change captured by the fiber cable installed in Monitoring Well 73-22. FIG. 8 illustrates the modeled cross- well strain change. The recorded data are one of the first of their kind during the stimulation of a well in a geothermal formation. The model results exhibit similar features as observed in the field data and help to explain the observations. This response occurs because the process of fracture propagation causes a stress shadow effect away from the fracture, which is also coupled with a change in strain. The strength of this effect in a particular location is influenced by fracture aperture, fracture geometry, fracture azimuth, formation elastic properties, as well as the distance between the observation pointrelative to the propagating fractures. Generally, the closer the fracture plane is to the monitoring well, the stronger the observed response.

[0062] As the treatment of a given stage begins, extension of the fiber at depths between the upper and lower crack tips may be observed, and compression above the upper crack tip may be observed (see model response shown in FIG. 8). The location of the polarity flip along the measured depth, observed in the LF-DAS data, is related to the fracture height. The polarity reversals in time are linked to fracture aperture changes associated with the treatment schedule. For the treatment stage shown in FIG. 6, the fracture plane was relatively close to the observation well (< 500 ft). In this case, the polarity flip location in depth can provide a reasonable estimate of fracture half-height. The location of the polarity flips in depth is about 7,250 ft for recorded data and 7,300 ft for the model. The depth of the lateral at this stage is about 7,700 ft TVD. The fracture height was about 450 ft above the wellbore. The data indicate rapid fracture height growth. This height growth occurs rapidly, given that the polarity reversal in depth remains relatively constant throughout the treatment. Upon stage completion, polarity reversal in time occurs, which is caused by a decrease in fracture aperture (note that the LF-DAS data is presented in units of strain rate and not total strain).

[0063] FIG. 7 summarizes pressure and LF-DAS data recorded in the vertical monitoring offset well throughout the treatment of all 16 stages. The first LF-DAS signal was observed during stage 1 stimulation of the 34A-22 well. The fracture planes from the first stage are located more than 1,500 ft away from the 73-22 monitoring well. This observation is confirmed by modelling the LF-DAS data with a history-matched ResFrac simulation. The field and modeled data share the same behavior. The shadow half-height indicated by the polarity flip is shortened from stage 1 to 9 and increased afterward. The amplitude of LF-DAS signals increased from stage 1 to 9 as the distance between stimulated fractures and the observation well reduced. The signal from stage 9 has a complex behavior due to the very close (<100 ft) vicinity of multiple fracture planes to the monitoring fiber or even within the fracture corridor. This also indicates a fracture half-length of more than the horizontal offset between 34A-22 and 73-22 wells (about 800 ft). Stages 10-16 haveweaker signals, which can be explained by fracture azimuth and possibly lower than 800 ft fracture half-length, which agrees with the model. A regularly spaced signal was observed from 6,000 ft to 6,500 ft around 26 July. LF-DAS is very sensitive to temperature, and this signal is associated with heating and cooling downhole instruments placed at this location for a short time.

[0064] A horizontal doublet well system was drilled in the southern margin of the Blue Mountain geothermal field (Injection Well 34A-22 and Production Well 34- 22), and a deep vertical monitoring well was also drilled for the purposes of reservoir characterization and stimulation treatment monitoring (Monitoring Well 73-22). The target reservoir lithology is a predominantly metasedimentary (phyllite and quartzite) with granitic intrusives (diorite and granodiorite). The laterals of the two horizontal wells were landed at a true vertical depth of approximately 7,700 ft and the productive lateral sections each extended roughly 3,250 ft. The curve sections were drilled at build rates of approximately 10 degrees of inclination per 100 ft from vertical up to fully horizontal (inclinations along the lateral range from 87° to 92°). The maximum recorded temperature along the lateral was 376 °F.While drilling, the downhole temperature was measured using an MWD tool near the bit, and we observed that downhole temperatures never exceeded 250 °F. The horizontal wells were drilled from the same pad. The optimal production well trajectory required successfully drilling a complex three-dimensional curve with a combination of back-build and lateral step-out. No wellbore stability issues were observed.

[0065] A 16-stage plug-and-perf orate style stimulation treatment was performed on Injection Well 34A-22. A total of 17,000 bbl of slickwater fluid and 7.3 million lbs of proppant were pumped during the stimulation. In-well DAS measurements confirmed that fractures initiated at 100% of the perforation clusters, indicating that fracture breakdown and initiation is not a major barrier in hard rock lithologies. Inwell DTS measurements were used to evaluate the downhole temperature conditions that the wireline tools (zonal isolation plugs and perforation charges) were exposed to. Significant wellbore cooling occurred due to injecting at high rates duringwireline pumpdown operations and during the stimulation of each stage, such that wellbore temperatures never exceeded 300 °F (most stages never exceeded 250 °F).

[0066] The distribution of microseismic events as well as direct strain measurements and bottomhole pressure measurements in an offset vertical well were used to constrain the geometry of the stimulated reservoir volume created during the 34A-22 treatment. Median fracture length and fracture height were estimated to be approximately 1800 ft and 750 ft, respectively, which is large enough for economic reservoir performance.

[0067] The results described herein show that horizontal well geothermal drilling programs in high-temperature, hard rock settings are feasible. A comprehensive data acquisition program may be used, such as including diagnostic fracture injection tests, downhole microseismic monitoring, in-well and cross well distributed fiber optic sensing, or reservoir pressure monitoring with downhole gauges. The combination of multiple independent datasets may be used to provide detailed insight into downhole conditions during stimulation treatment, a well-characterized understanding of stimulated reservoir volume geometry, or other properties that impact reservoir performance of a doublet well system. Reservoir simulation forecasts and history matching may be used to replicate reservoir response observations, including physics-based modeling to effectively evaluate reservoir performance of horizontal well geothermal systems.

[0068] FIG. 9 illustrates a flowchart showing a technique 900 for horizontal geothermal drilling and multistage hydraulic stimulation treatment. The technique 900 includes an operation 902 to pump treatment into a horizontal well connecting an injection well and a production well, the horizontal well comprising a set of hydraulically conductive fractures at the horizontal well. The technique 900 includes an operation 904 to receive in-well fiber optics data related to stimulation treatment effectiveness. In an example, the in-well fiber optics data includes fiberbased multi-well data.

[0069] The technique 900 includes an operation 906 to determine a well condition of the horizontal well based on the in- well fiber optics data. Operation 906may include determining a fracture orientation, a fracture length, a fracture height, a fracture propagation rate, or the like.

[0070] In an example, the in-well fiber optics data includes distributed acoustic sensing (DAS) data. Operation 906 may include verifying whether fracture initiation occurred at each perforation cluster of the horizontal well using the DAS data. For example, operation 906 includes identifying that the fracture initiation occurred and that each perforation cluster received flow for a full duration of a stage. The DAS data may include an amplitude signal as a proxy for a flow rate at each perforation cluster. Operation 906 may include determining the well condition includes determining a flow allocation across all perforation clusters in a stage using the DAS data. Operation 906 may include determining a stage isolation for the horizontal well, using the DAS data.

[0071] In an example, the in-well fiber optics data includes distributed temperature sensing (DTS) data. Operation 906 may include determining whether any leakage is occurring into a previous stage using the DTS data. Determining whether any leakage is occurring may include determining whether leakage is occurring around a plug or behind a casing.

[0072] In view of the disclosure above, various examples are set forth below. It should be noted that one or more features of an example, taken in isolation or combination, should be considered within the disclosure of this application.

[0073] Example 1 is a method comprising: pumping treatment into a horizontal well connecting an injection well and a production well, the horizontal well comprising a set of hydraulically conductive fractures at the horizontal well; receiving in-well fiber optics data related to stimulation treatment effectiveness; and determining a well condition of the horizontal well based on the in-well fiber optics data.

[0074] In Example 2, the subject matter of Example 1 includes, wherein the inwell fiber optics data includes distributed acoustic sensing (DAS) data, and wherein determining the well condition includes verifying whether fracture initiation occurred at each perforation cluster of the horizontal well using the DAS data.

[0075] In Example 3, the subject matter of Example 2 includes, wherein determining the well condition includes identifying that the fracture initiation occurred and that each perforation cluster received flow for a full duration of a stage.

[0076] In Example 4, the subject matter of Examples 2-3 includes, wherein the DAS data includes an amplitude signal, and further comprising determining the well condition by using the amplitude signal as a proxy for a flow rate at each perforation cluster.

[0077] In Example 5, the subject matter of Examples 1-4 includes, wherein the in-well fiber optics data includes distributed acoustic sensing (DAS) data, and wherein determining the well condition includes determining a flow allocation across all perforation clusters in a stage using the DAS data.

[0078] In Example 6, the subject matter of Examples 1-5 includes, wherein the in-well fiber optics data includes distributed acoustic sensing (DAS) data, and wherein determining the well condition includes determining a stage isolation for the horizontal well, using the DAS data.

[0079] In Example 7, the subject matter of Examples 1-6 includes, wherein the in-well fiber optics data includes distributed temperature sensing (DTS) data, and wherein determining the well condition includes determining whether any leakage is occurring into a previous stage using the DTS data.

[0080] In Example 8, the subject matter of Example 7 includes, wherein determining whether any leakage is occurring includes determining whether leakage is occurring around a plug or behind a casing.

[0081] In Example 9, the subject matter of Examples 1-8 includes, wherein the in-well fiber optics data includes fiber-based multi-well data.

[0082] In Example 10, the subject matter of Examples 1-9 includes, wherein determining the well condition includes determining a fracture orientation, a fracture length, a fracture height, or a fracture propagation rate.

[0083] Example 11 is a method comprising: receiving in-well fiber optics data related to stimulation treatment effectiveness at a horizontal well comprising a set ofhydraulically conductive fractures; and determining a well condition of the horizontal well based on the in-well fiber optics data.

[0084] In Example 12, the subject matter of Example 11 includes, wherein the inwell fiber optics data includes distributed acoustic sensing (DAS) data, and wherein determining the well condition includes verifying whether fracture initiation occurred at each perforation cluster of the horizontal well using the DAS data.

[0085] In Example 13, the subject matter of Example 12 includes, wherein determining the well condition includes identifying that the fracture initiation occurred and that each perforation cluster received flow for a full duration of a stage.

[0086] In Example 14, the subject matter of Examples 12-13 includes, wherein the DAS data includes an amplitude signal, and further comprising determining the well condition by using the amplitude signal as a proxy for a flow rate at each perforation cluster.

[0087] In Example 15, the subject matter of Examples 11-14 includes, wherein the in-well fiber optics data includes distributed acoustic sensing (DAS) data, and wherein determining the well condition includes determining a flow allocation across all perforation clusters in a stage using the DAS data.

[0088] In Example 16, the subject matter of Examples 11-15 includes, wherein the in-well fiber optics data includes distributed acoustic sensing (DAS) data, and wherein determining the well condition includes determining a stage isolation for the horizontal well, using the DAS data.

[0089] In Example 17, the subject matter of Examples 11-16 includes, wherein the in-well fiber optics data includes distributed temperature sensing (DTS) data, and wherein determining the well condition includes determining whether any leakage is occurring into a previous stage using the DTS data.

[0090] In Example 18, the subject matter of Example 17 includes, wherein determining whether any leakage is occurring includes determining whether leakage is occurring around a plug or behind a casing.

[0091] In Example 19, the subject matter of Examples 11-18 includes, wherein the in-well fiber optics data includes fiber-based multi-well data.

[0092] In Example 20, the subject matter of Examples 11-19 includes, wherein determining the well condition includes determining a fracture orientation, a fracture length, a fracture height, or a fracture propagation rate.

[0093] Example 21 is at least one machine-readable medium including instructions that, when executed by processing circuitry, cause the processing circuitry to perform operations to implement of any of Examples 1-20.

[0094] Example 22 is an apparatus comprising means to implement of any of Examples 1-20.

[0095] Example 23 is a system to implement of any of Examples 1-20.

[0096] Example 24 is a method to implement of any of Examples 1-20.

[0097] The above detailed description includes references to the accompanying drawings, which form a part of the detailed description. The drawings show, by way of illustration, specific embodiments in which the inventive subject matter may be practiced. These embodiments are also referred to herein as “examples.” Such examples may include elements in addition to those shown or described. However, the present inventors also contemplate examples in which only those elements shown or described are provided. Moreover, the present inventors also contemplate examples using any combination or permutation of those elements shown or described (or one or more aspects thereof), either with respect to a particular example (or one or more aspects thereof), or with respect to other examples (or one or more aspects thereof) shown or described herein. In the event of inconsistent usages between this document and any documents so incorporated by reference, the usage in this document controls.

[0098] In this document, the terms “a” or “an” are used, as is common in patent documents, to include one or more than one, independent of any other instances or usages of “at least one” or “one or more.” In this document, the term “or” is used to refer to a nonexclusive or, such that “A or B” includes “A but not B,” “B but not A,” and “A and B,” unless otherwise indicated. In this document, the terms “including” and “in which” are used as the plain-English equivalents of the respective terms “comprising” and “wherein.” Also, in the following claims, the terms “including” and “comprising” are open-ended, that is, a system, device,article, composition, formulation, or process that includes elements in addition to those listed after such a term in a claim are still deemed to fall within the scope of that claim. Moreover, in the following claims, the terms “first,” “second,” and “third,” etc. are used merely as labels, and are not intended to impose numerical requirements on their objects.

[0099] The above description is intended to be illustrative, and not restrictive. For example, the above-described examples (or one or more aspects thereof) may be used in combination with each other. Other embodiments may be used, such as by one of ordinary skill in the art upon reviewing the above description. The Abstract is provided to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims. Also, in the above Detailed Description, various features may be grouped together to streamline the disclosure. This should not be interpreted as intending that an unclaimed disclosed feature is essential to any claim. Rather, inventive subject matter may lie in less than all features of a particular disclosed embodiment. Thus, the following claims are hereby incorporated into the Detailed Description as examples or embodiments, with each claim standing on its own as a separate embodiment, and it is contemplated that such embodiments may be combined with each other in various combinations or permutations. The scope of the inventive subject matter should be determined with reference to the appended claims, along with the full scope of equivalents to which such claims are entitled.

Claims

CLAIMSWhat is claimed is:

1. A method comprising: pumping treatment into a horizontal well connecting an injection well and a production well, the horizontal well comprising a set of hydraulically conductive fractures at the horizontal well; receiving in-well fiber optics data related to stimulation treatment effectiveness; and determining a well condition of the horizontal well based on the in-well fiber optics data.

2. The method of claim 1 , wherein the in- well fiber optics data includes distributed acoustic sensing (DAS) data, and wherein determining the well condition includes verifying whether fracture initiation occurred at each perforation cluster of the horizontal well using the DAS data.

3. The method of claim 2, wherein determining the well condition includes identifying that the fracture initiation occurred and that each perforation cluster received flow for a full duration of a stage.

4. The method of claim 2, wherein the DAS data includes an amplitude signal, and further comprising determining the well condition by using the amplitude signal as a proxy for a flow rate at each perforation cluster.

5. The method of claim 1, wherein the in- well fiber optics data includes distributed acoustic sensing (DAS) data, and wherein determining the well condition includes determining a flow allocation across all perforation clusters in a stage using the DAS data.

6. The method of claim 1 , wherein the in- well fiber optics data includes distributed acoustic sensing (DAS) data, and wherein determining the well condition includes determining a stage isolation for the horizontal well, using the DAS data.

7. The method of claim 1, wherein the in- well fiber optics data includes distributed temperature sensing (DTS) data, and wherein determining the well condition includes determining whether any leakage is occurring into a previous stage using the DTS data.

8. The method of claim 7, wherein determining whether any leakage is occurring includes determining whether leakage is occurring around a plug or behind a casing.

9. The method of claim 1, wherein the in- well fiber optics data includes fiberbased multi-well data.

10. The method of claim 1 , wherein determining the well condition includes determining a fracture orientation, a fracture length, a fracture height, or a fracture propagation rate.

11. A method comprising: receiving in-well fiber optics data related to stimulation treatment effectiveness at a horizontal well comprising a set of hydraulically conductive fractures; and determining a well condition of the horizontal well based on the in-well fiber optics data.

12. The method of claim 11, wherein the in- well fiber optics data includes distributed acoustic sensing (DAS) data, and wherein determining the well condition includes verifying whether fracture initiation occurred at each perforation cluster of the horizontal well using the DAS data.

13. The method of claim 12, wherein determining the well condition includes identifying that the fracture initiation occurred and that each perforation cluster received flow for a full duration of a stage.

14. The method of claim 12, wherein the DAS data includes an amplitude signal, and further comprising determining the well condition by using the amplitude signal as a proxy for a flow rate at each perforation cluster.

15. The method of claim 11, wherein the in- well fiber optics data includes distributed acoustic sensing (DAS) data, and wherein determining the well condition includes determining a flow allocation across all perforation clusters in a stage using the DAS data.

16. The method of claim 11, wherein the in- well fiber optics data includes distributed acoustic sensing (DAS) data, and wherein determining the well condition includes determining a stage isolation for the horizontal well, using the DAS data.

17. The method of claim 11, wherein the in- well fiber optics data includes distributed temperature sensing (DTS) data, and wherein determining the well condition includes determining whether any leakage is occurring into a previous stage using the DTS data.

18. The method of claim 17, wherein determining whether any leakage is occurring includes determining whether leakage is occurring around a plug or behind a casing.

19. The method of claim 11, wherein the in- well fiber optics data includes fiber-based multi-well data.

20. The method of claim 11 , wherein determining the well condition includes determining a fracture orientation, a fracture length, a fracture height, or a fracture propagation rate.

Images