Managing system pressure within shear induced fracture field during hydrualic fracturing operations to increase the effective energy that can be delivered into the reservoir

Abstract

A method comprises obtaining, via one or more sensors, measurements of a fracture system proximate one or more wellbores formed in a subsurface formation while hydraulically fracturing one or more wellbores. The method comprises identifying one or more shear induced fracture fields within the fracture system based on the measurements. The method comprises determining a pressure ceiling of the fracture system. The method comprises performing a wellbore operation to minimize wasted effective energy put into the subsurface formation, via the hydraulic fracturing, based on the shear induced fracture fields and the pressure ceiling.

Description

TECHNICAL FIELD

[0001] This disclosure relation generally to the field of hydraulically fracturing a wellbore in a subsurface formation and more particular to the field managing pressure in a shear induced fracture field.BACKGROUND

[0002] In hydrocarbon recovery operations, fluid and sand may be pumped into a wellbore to hydraulically fracture a subsurface formation. The pump rate and pressure from the fluid may fracture the subsurface formation, creating a conduit for the fluid in the subsurface formation to flow to the wellbore and ultimately to the surface. Sand may be pumped with the fluid and placed into the fractures to support said fractures. A wellbore may be hydraulically fractured in one or more stages, where each stage includes clusters of perforations in which the fluid and sand may enter the subsurface formation to fracture said subsurface formation.BRIEF DESCRIPTION OF THE DRAWINGS

[0003] Implementations of the disclosure may be better understood by referencing the accompanying drawings.

[0004] FIG. 1 is an illustration depicting an example multi-well system, according to some implementations.

[0005] FIG. 2 is a schematic depicting example rock mechanics, according to some implementations.

[0006] FIG. 3 is a schematic depicting an example multi-well system, according to some implementations.

[0007] FIG. 4 is a schematic depicting an example multi-well system, according to some implementations.

[0008] FIG. 5 is a schematic depicting an example multi-well system, according to some implementations.

[0009] FIG. 6 is a schematic depicting an example multi-well system, according to some implementations.

[0010] FIG. 7 is a schematic depicting an example multi-well system, according to some implementations.

[0011] FIG. 8 is a schematic depicting an example multi-well system, according to some implementations.

[0012] FIG. 9 is a flowchart depicting example operations for managing pressure of a fracture system, according to some implementations.

[0013] FIGS. 10A-10B are charts depicting measurements obtained during hydraulic fracturing operations, according to some implementations.

[0014] FIG. 11 is a block diagram depicting an example computer, according to some implementations.DESCRIPTION

[0015] The description that follows includes example systems, methods, techniques, and program flows that embody aspects of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. For instance, this disclosure refers to performing wellbore operations on offset wells during hydraulic fracturing operations. Aspects of this disclosure can also be applied to modeling hydraulic fracturing operations for future wells / multiwell pads, field development, etc. For clarity, some well-known instruction instances, protocols, structures, and operations have been omitted.

[0016] Example implementations relate to managing pressure within a fracture system during hydraulic fracturing operations. During the hydraulic fracturing of a horizontal wellbore formed in a subsurface formation (i.e., shale), multiple fractures may be formed along the wellbore which may result in significant stress interference between the strain field of respective fractures. In some implementations, the level of stress may increase significantly as more fractures interfere with each other. Accordingly, stress interference may occur between clusters, stages, wellbores, etc., resulting in shear induced fracture fields between the clusters, stages, wellbores, etc. Increased strain levels within these regions of increased stress interference may result in rock failure in shear that include Mode 2 type failures (in-plane shear failure such as bedding plane slippage) and / or Mode 3 type failures (out of plane shear failure such as shear induced tensile failure), forming a complex system of fractures in these regions of stress interference (i.e., a shear induced fracture field). In hydrocarbon recovery operations, multiple wellbores may be drilled from a single pad and / or multiwell pads. The hydraulic fracturing of these multi-well systems may generate a fracture system within the subsurface formation, including shear induced fracture fields. In conventional operations, similar fracture treatments may be pumped on every stage of each wellbore, resulting in an increase in stress and pressure interference and subsequently generating a complex fracture system. In some implementations, the system may increase in complexity if the pressure and stress interference is sufficient to induce compressional shear failure in compressed regions between fractures, resulting in shear induced fracture fields.

[0017] In some implementations, the shear induced fracture fields may initially be dry (i.e., not in hydraulic communication with the fracturing fluid in the hydraulic fractures from the Mode 1 type failures). However, the fractures within the shear induced fracture field may begin to dilate as more energy is added to the fracture system (i.e., fracturing fluid is pumped into the subsurface formation resulting in an increase in the fracture system pressure) and the fracturing fluid may enter the shear induced fracture field from the higher pressured hydraulic fractures until the pressures may equalize. Initially, the fractures within the shear induced fracture field may increase the effective permeability of the subsurface formation. However, as the pressure approaches the overburden pressure and / or some other critical value (such as a pressure level resulting in activation of a fault), the preferred fracture orientation may transition from vertical (i.e., perpendicular to the overburden pressure) to horizontal (i.e., parallel to the overburden pressure), and the fracturing fluid pumped into the subsurface formation (i.e., energy) may lose effectiveness This critical value (pressure ceiling) may limit the amount of effective energy that may be placed within a fracture system and any additional energy placed into the system when the pressure reaches the pressure ceiling may be wasted. For instance, once pressure in the fracture system increases above the pressure ceiling, the fracturing fluid may flow through the fractures of the shear induced fracture field rather than creating additional fractures in the rock to increase the effective permeability of the rock, resulting in wasted effective energy of the fracturing fluid.

[0018] In some implementations, during hydraulic fracturing operations of one or more wellbore in a multi-well system, the fracture system pressure behavior may be monitored through the use of one or more sensors. For example, sensors such as disposable fiber optic cables, permanently installed fiber cables, externally ported pressure sensors, etc. may be positioned downhole in one or more wellbores. During hydraulic fracturing operations of one or more wellbores, the one or more sensors positioned in one or more offset wellbores to the wellbores being hydraulically fractured may obtain measurements such as strain measurements, acoustic measurements, pressure measurements, etc. of the subsurface formation. In some implementations, the measurements may be utilized to identify the generation and / or growth of shear induced fracture fields within the fracture system. For instance, the shear induced fracture field comprising Mode 2 failures and / or Mode 3 failures may be identified, via the measurements, between clusters, between stages, between wellbores, etc. Events within the measurements may indicate shear induced fracture fields have formed and may potentially waste the effective energy put into the subsurface formation. In some implementations, a pressure ceiling of the fracture system may be determined. The pressure ceiling may be determined based on the overburden pressure or any other critical value. The pressure ceiling may indicate the fracture system pressure in which effective energy may be wasted if exceeded. Accordingly, wellbore operations may be performed based on the strain induced fracture fields and the pressure ceiling to minimize wasted effective energy put into the subsurface formation. The one or more sensors may allow for effectively managing completion sequencing in multi-well systems to maximize the total amount of energy that may be deployed into the subsurface formation. Additionally, the monitoring of the fracture system may be utilized for adjusting wellbore completions and enabling these decisions to be made in real time during hydraulic fracturing operations. Additionally, the usage of drainage wellbores and / or production wellbores (i.e., offset wellbores to the wellbore being hydraulically fractured) to flow fluid out of the system may allow for the management of the fracture system pressure in real time and / or to enable more energy to be applied to the subsurface formation during hydraulic fracturing operations.

[0019] Operations may include repressuring locally depleted regions (such as close to a depleted parent wellbore) prior to hydraulic fracturing a new offset well. This may assist in reducing asymmetry and create a more uniform fracture field. Operations may include adjusting the sequence of completion to assist in distributing the pressure over a larger area or volume in the subsurface formation to enable energy to be placed within the total system by managing the interference between wells more effectively. For example, the sequence of hydraulically fracturing stages on two or more wells on a pad may be adjusted such that the fracture system pressure is distributed over a larger area and the fracture system pressure does not exceed the pressure ceiling. Operations may include altering the completion design to pump smaller volumes of fracturing fluid as the fracture system pressure approaches the ceiling pressure to limit the fracture system pressure increasing around the new completion. Operations may include flowing any open offset wellbores that may be in hydraulically communication with the fracture system if the fracture system pressure reached the pressure ceiling. This may allow additional treatments (such as additional stages to be pumped) to be performed without exceeding the pressure ceiling. The wellbore to be flowed during the hydraulic fracturing operations of the new well may include parent wellbores from the same pad, offset wellbores from an offset pad, etc. In some implementations, the wellbore can be flowed following one frac stage prior to that stage being isolated and the next stage is perforated. In some implementations, completion configurations such as open hole completions, slotted liner completions, cased and perforated completions, etc. may be preinstalled within a multiwell system such that they may be flowed back to manage the fracture system pressure during hydraulic fracturing operations. Operations may include managing fracture system pressure during infill drilling. For example, in some implementations it may be desirable to plan to drill infill wells when the pressure within the current fracture system has been depleted to a desirable level via production of the subsurface formation fluids. Because this type of planning may essentially stabilize the previously fractured region, the management of the fracture system pressure during hydraulic fracturing operations of the new infill wells may be highly beneficial in locations where casing damage due to fault activation, induced seismicity, etc. may be a problem. This may highlight the potential importance to drilling and / or completion operations in regions that may be prone to casing damage and / or seismic activity. In some implementations, wellbores from offset pads may be placed strategically close to or within a current multi-well system such that they may be flowed back to manage the fracture system pressure and / or to enable greater amounts of energy to be applied to the formation.

[0020] An increase in energy applied into the fracture system may generate more shear induced fractures, helping to improve the effective permeability of the subsurface formation within a multi-well system and enhancing the production performance. In implementations where treatments may be reduced to prevent the fracture system pressure from exceeding the pressure ceiling, cost savings may be observed (due to less fluid pumped into the system, time pumping, etc.). In some implementations, a decrease in fracture treatment size for interior wells of a multi-well system may result in lower costs. Additionally, more wellbore may be able to be drilled within the given multi-well system to enhance production rates and / or recovery factors, resulting in an increase in asset value and / or a reduction in operating costs. With infill drilling in a multi-well system, the costs for casing damage and / or induced seismicity may be reduced, allowing for closer well spacing and / or increased recovery factors.Example System

[0021] FIG. 1 is an illustration depicting an example multi-well system, according to some implementations. In particular, FIG. 1 is a schematic of a multi-well system 100 that includes a wellbore 102 and a wellbore 108 in a subsurface formation 101. The wellbore 102 includes casing 106 and a number of perforations 190A-190H being made in the casing 106 at different depths to allow reservoir fluids (i.e., oil, water, and gas) from the subsurface formation 101 to flow into the wellbore 102. Similarly, the wellbore 108 includes casing 110 and a number of perforations 180A-180H being made in the casing 110 to allow reservoir fluids (i.e., oil, water, and gas) from the subsurface formation 101 to flow into the wellbore 108. During hydraulic fracturing operations of the wellbores 102108, fracturing fluid, with or without sand, may be pumped into the subsurface formation 101, via the perforations 190A-190H and perforations 180A-180H, to hydraulically fracture the rock such that reservoir fluid may flow into the wellbore 102, 108, respectfully.

[0022] In some implementations, one or more sensors may be positioned in a wellbore to obtain measurements while an offset well is being hydraulically fractured. For example, the wellbore 102 may include a fiberoptic cable 120 to obtain strain measurements, temperature measurements, derived pressure measurements (from strain measurements), etc. of the subsurface formation 101 while the wellbore 108 is being hydraulically fractured. The fiberoptic cable 120 may extend from the wellhead 114 on the surface 111 to the subsurface along the wellbore 102. The fiber optic cable 120 may be cemented in place in the annular space between the casing 106 of the wellbores 102 and the subsurface formation 101. The fiber optic cable 120 may be clamped to the outside of the casing 106 during deployment and protected by centralizers and cross coupling clamps. The fiber optic cables 120 may be included with coiled tubing, wireline, loose fiber using coiled tubing, or gravity deployed fiber coils that unwind the fiber as the coils are moved in the wellbore 102. The fiber optic cable 120 also may be deployed with pumped down coils and / or self-propelled containers. Additional deployment options for the fiber optic cable 120 can include coil tubing and wireline deployed coils where the fiber optic cables 120 are anchored at the toe of the wellbore. In such implementations the fiber optic cable 120 can be deployed when the wireline or coiled tubing is removed from the well. The fiber optic cable 120 may house one or more optical fibers, and the optical fibers may be single mode fibers, multi-mode fibers, or a combination of single mode and multi-mode optical fibers. The distribution of sensors shown in FIG. 1 is for example purposes only. Any suitable sensor deployment may be used.

[0023] The fiber optic cable 120 may be used for distributed sensing where acoustic, vibration, strain, and temperature measurements may be collected downhole in the wellbores 102. The measurements may be collected at various positions distributed along the fiber optic cable 120. For example, data may be collected every 1-3 ft along the full length of the fiber optic cable 120 downhole along the horizontal section of the wellbore. Fiber optic interrogation unit 122 of the wellbore 102 may be located on the surface 111 of the multi-well system 100. The fiber optic interrogation units 122 may be directly coupled to the fiber optic cables 120. Alternatively, the fiber optic interrogation units 122 may be coupled to a fiber stretcher module, wherein the fiber stretcher module is coupled to the fiber optic cable 120. The fiber optic interrogation unit 122 may receive measurement values taken and / or transmitted along the length of the fiber optic cable 120 such as acoustic, temperature, strain, etc. The fiber optic interrogation unit 122 may be electrically connected to a digitizer to convert optically transmitted measurements into digitized measurements.

[0024] The fiber optic interrogation unit 122 may operate using various sensing principles including but not limited to amplitude-based sensing systems like Distributed Temperature Sensing (DTS), Distributed Acoustic Sensing (DAS), Low Frequency Distributed Acoustic Sensing (LFDAS), Distributed Vibration Sensing (DVS), and Distributed Strain Sensing (DSS). For example, the DTS system may be based on Raman and / or Brillouin scattering. A DAS system may be a phase sensing-based system based on interferometric sensing using homodyne or heterodyne techniques where the system may sense phase or intensity changes due to constructive or destructive interference. The DAS system may also be based on Rayleigh scattering and in particular coherent Rayleigh scattering. A DSS system may be a strain sensing system using dynamic strain measurements based on interferometric sensors or static strain sensing measurements using Brillouin scattering. DAS systems based on Rayleigh scattering may also be used to detect dynamic strain events. Temperature effects may in some cases be subtracted from both static and / or dynamic strain events, and temperature profiles may be measured using Raman based systems and / or Brillouin based systems capable of differentiating between strain and temperature, and / or any other optical and / or electronic temperature sensors, and / or any other optical and / or electronic temperature sensors, and / or estimated thermal events.

[0025] In some implementations, the fiber optic interrogation unit 122 may measure changes in optical fiber properties between two points in an optical fiber at any given point, and these two measurement points move along the optical sensing fiber as light travels along the optical fiber. Changes in optical properties may be induced by strain, vibration, acoustic signals and / or temperature as a result of the fluid flow. Phase and intensity based interferometric sensing systems are sensitive to temperature and mechanical, as well as acoustically induced, vibrations. DAS data can be converted from time series data to frequency domain data using Fast Fourier Transforms (FFT) and other transforms, like wavelet transforms, also may be used to generate different representations of the data. Various frequency ranges can be used for different purposes and where low frequency signal changes may be attributed to formation strain changes or fluid movement and other frequency ranges may be indicative of fluid movement. Various techniques may be applied to generate indicators of events related to the generation and / or expansion of shear induced fracture fields during hydraulic fracturing operations. Although FIG. 1 depicts the fiber optic cable 120 in the wellbore 102, a fiber optic cable 120 may also be positioned in the wellbore 108 to obtain measurements when the wellbore 102 is hydraulically fractured.

[0026] The wellbore 102 may also include pressure sensors, such as externally ported pressure sensors 130, 132, to measure the formation pressure while the offset wellbore 108 is hydraulically fractured. Although FIG. 1 depicts the externally ported pressure sensors 130, 132 at the heel and toe of the wellbore 102, respectively, the externally ported pressure sensors 130, 132 may be positioned at any suitable location in the wellbore 102. Although FIG. 1 depicts the externally ported pressure sensors 130, 132 external to the casing 106 of the wellbore 102, externally ported pressure sensors 130, 132 may also be positioned in the wellbore 108 to obtain measurements when the wellbore 102 is hydraulically fractured.

[0027] During the hydraulic fracturing operations of wellbore 102 and / or wellbore 108, shear induced fracturing fields may be generated and / or dilated. For example, the shear induced fracturing fields comprising Mode 2 and / or Mode 3 failures may form between clusters of a stage, between stages of a wellbore, between clusters and / or stages of offset wellbores, etc. In some implementations, the fiber optic cable 120 and / or the externally ported pressure sensors 130, 132 may obtain measurements of the subsurface formation 101 to detect and / or monitor the subsurface formation 101 and the shear induced fracture fields.

[0028] A computer 170 may be communicatively coupled to the fiber optic interrogation units 122, externally ported pressure sensors 130, 132, and other sensors in the multi-well system 100. The computer 170 may include a signal processor to perform various signal processing operations on signals captured by the fiber optic interrogation units 122, externally ported pressure sensors 130, 132, and / or other components of the multi-well system 100. The computer 170 may have one or more processors and a memory device to analyze the measurements and graphically represent analysis results on a display device. The computer 170 may include machine-readable instructions that, when executed by a processor, detect shear induced fracture fields, determine when energy is being wasted due to the shear induced fracture fields, determining a pressure ceiling of the shear induced fracture field, and generating / performing a wellbore operation to minimize wasted effective energy as described herein based on the measurements and pressure ceiling. Although FIG. 1 depicts a system with multiple wellbores, embodiments described herein may also be applicable to other systems such as a single well system, multiple pads, etc. An example of the computer 170 is depicted in FIG. 11, and further described below.

[0029] FIG. 2 is a schematic depicting example rock mechanics, according to some implementations. In particular, FIG. 2 includes rock mechanic schematics 200 of a heterogeneous rock 202. The heterogeneous rock 202 depicts the normal state of stress on a rock, the normal state of stress including compressional stress 204 acting normal to the rock layers and shear stress 206 acting normal to compressional stress 204. The heterogeneous rock 202 includes multiple layer that may represent different layers of rock in a subsurface formation or different lamination layers within a rock layer. During hydraulic fracturing operations, the energy (i.e., high pressured fracturing fluid) injected into the subsurface formation may generate fractures that may be oriented in the direction perpendicular to the minimum principal stress and parallel to the maximum principal stress. The rock of the subsurface formation may be characterized by the tensile stress that led to the failure of the rock, otherwise known as a Mode 1 type failure. As the pressure of the fracture system increases, regions of the rock between the fractures may experience an increase in stress, resulting in a strain field and / or local stress field. As energy is added to the fracture system during the hydraulic fracturing operations, Mode 2 failures 212 (i.e., shear failure and / or slippage between layers, laminations, etc.) and / or Mode 3 failures 210 (i.e., shear induced tensile fractures orthogonal to the slip planes) may be initiated.

[0030] FIG. 3 is a schematic depicting an example multi-well system, according to some implementations. FIG. 3 includes region 322 to depict where strain induced fracture fields may occur between clusters of a frac stage. The multi-well system 300 includes an overhead view of the horizontal section of three horizontal wellbores 301, 303, and 305 drilled in a subsurface formation. The wellbores 301, 303, and 305 may be from a single multi-well pad, wellbores from multiple pads in close proximity, etc. A stage of the wellbore 301 comprising 5 clusters has been hydraulically fractured to generate a fracture system. Mode 1 type failures may occur due to the energy (high pressure fracturing fluid) injected into the subsurface formation, forming fractures from each cluster such as fractures 302, 304, 306, 308, and 310. Strain fields 312, 314, 316, 318, and 320 may be generated around the respective fractures 302, 304, 306, 308, and 310 as a result of the energy placed into the fracture system. In some implementations, stress interference may occur between overlapping strain fields 312, 314, 316, 318, and 320. For example, stress interference may occur in the region 322 where the strain fields 312, 314, 316, 318, and 320 may be located. An increase in stress interference may result in an increase in the likelihood of shear failures occurring, where Mode 2 and / or Mode 3 failures may be initiated to generate a shear induced fracture field and subsequently a complex fracture system. In some implementations, exterior regions such as exterior regions to the strain field 312 and / or 320 may stabilize because there may be no stress interference. As more energy is injected into the fracture system, the Mode 2 and / or Mode 3 failures may dilate and take energy from the initial fractures 302, 304, 306, 308, and 310. In some implementations, the stress induced fracture fields may increase the effective permeability of the rock. However, the fracture system pressure may increase to a pressure ceiling as energy is injected into the fracture system and the strain induced fractures continue to dilate, resulting in wasted effective energy placed into the system.

[0031] FIG. 4 is a schematic depicting an example multi-well system, according to some implementations. The multi-well system 400 includes an overhead view of the horizontal section of three horizontal wellbores 401, 403, and 405 drilled in a subsurface formation. The wellbores 401, 403, and 405 may be similar to the wellbore 301, 303, and 305 described in FIG. 3. After shutdown, fracturing fluid may no longer be injected into the subsurface formation. Accordingly, pressure in the fracture system may dissipate though the fracture system and / or pores within the subsurface formation, as depicted by the pressure response 402. In some implementations, the pressure may dissipate into the shear induced fractures until pressure may be equalized in the fracture system.

[0032] In some implementations, one or more sensors such as disposable fiber optic cables, externally ported pressure gauges, etc. may be positioned in one or more offset wellbores, such as wellbore 403 and / or wellbore 405, to the wellbore being hydraulically fractured (wellbore 401). The one or more sensors may be configured to obtain measurements such as strain, acoustic and / or pressure prior to, during, and / or after hydraulic fracturing operations. The measurements may indicate the initiation of strain induced fracture fields (Mode 2 and Mode 3 type failures) and the fracture system pressure relative to the ceiling pressure. In some implementations, the effects of the strain may be captured during hydraulic fracturing operations. The development and / or the pressure dissipation from the fracture system may transmit through the subsurface at slower speeds relative to the strain, as it may be controlled by the fracture dilation and / or leak off into closed fracture systems within the sheared region. However, the pressure signal may transmit faster once the fractures within the shear induced fracture field are open. Both pressure and / or strain measurements may be obtained by the one or more sensors positioned in the offset wells, allowing for the monitoring of the fracture system and management of the fracture system pressure to enable more effective energy to be applied to the rock. Pressure and strain data may be captured in one or more offset wellbore 403 and / or wellbore 405, and the measured pressure and strain responses may be correlated using the captured data, thus enabling the use of one or the other sensor type in a wellbore in order to measure relevant data. Externally ported pressure gauges may require pre-planning as they are deployed with the completion prior to hydraulic fracturing operations, whereas disposable fiber deployed using, for example, the Halliburton ExpressFiber service may be deployed on demand in any offset well during hydraulic fracturing operations, thus providing more flexibility to add sensing capabilities on demand. In some implementations, the term pressure measurement may indicate that externally ported pressure sensors are used to measure pressure. However, a substantially similar measurement may be derived from strain measurements obtained with disposable fiber optic sensors.

[0033] In some implementations, the fracture system pressure may stabilize approximately near the overburden pressure on the subsurface formation. Accordingly, a pressure ceiling may be determined, where it may be utilized as a threshold for the fracture system pressure and a ceiling as to how much effective energy may be put in to fracturing the rock. In some implementations, the pressure ceiling may be determined via other methods such as historical data from offset wellbores, wellbore logs, expert knowledge, etc. In some implementation, other geological factors may affect the pressure ceiling. For example, a fault proximate the fracture system may be present. The fault may hydraulically communicate with the fracture system, and may activate when the fracture system pressure reaches a specific value. Once activated, the pressure may dissipate away from the fracture system, resulting in wasted effective energy.

[0034] FIG. 5 is a schematic depicting an example multi-well system, according to some implementations. FIG. 5 includes region 522 to depict where strain induced fracture fields may occur between wellbores. The multi-well system 500 includes an overhead view of the horizontal section of three horizontal wellbores 501, 503, and 505 drilled in a subsurface formation. The wellbores 501, 503, and 505 may be similar to the wellbore 301, 303, and 305 described in FIG. 3. A stage of the wellbore 505 has been hydraulically fractured after the stage hydraulically fractured on the wellbore 501 (as described in FIG. 3). Similar to the hydraulic fracturing on the wellbore 501, the stage on the wellbore 505 has generated fractures 502, 504, 506, 508, and 510 from energy injected into the rock and strain fields 512, 514, 516, 518, and 520 may form proximate the respective fractures 502, 504, 506, 508, and 510. Stress interference may occur between strain fields 512, 514, 516, 518, and 520 (as described in FIG. 3). In some implementations, the fracture system between the wellbore 501 and the wellbore 505 may hydraulically communicate and / or stress interference may occur, resulting in a strain induced fracture field in region 522.

[0035] FIG. 6 is a schematic depicting an example multi-well system, according to some implementations. The multi-well system 600 includes an overhead view of the horizontal section of three horizontal wellbores 601, 603, and 605 drilled in a subsurface formation. The wellbores 601, 603, and 605 may be similar to the wellbore 301, 303, and 305 described in FIG. 3. Similar to FIG. 4, after shutdown, fracturing fluid may no longer be injected into the subsurface formation. Accordingly, pressure in the fracture system may dissipate though the fracture system and / or pores within the subsurface formation, as depicted by the pressure response 604. The pressure response 604 of the fracture system pressure may interact with the pressure response 602 from the wellbore 601. Measurements of the pressure and / or strain responses over time and distance may be used to plan operations as the responses may be indicative of energy movement within the fracture system and reservoir outside the fractured zone.

[0036] FIG. 7 is a schematic depicting an example multi-well system, according to some implementations. FIG. 7 includes region 722 to depict where strain induced fracture fields may occur between stages. The multi-well system 700 includes an overhead view of the horizontal section of three horizontal wellbores 701, 703, and 705 drilled in a subsurface formation. The wellbores 701, 703, and 705 may be similar to the wellbore 301, 303, and 305 described in FIG. 3. A second stage may be hydraulically fractured after the first stage (described in FIG. 3) has been hydraulically isolated in the wellbore. The second stage may generate fractures 702, 704, 706, 708, and 710 from energy injected into the rock and strain fields 712, 714, 716, 718, and 720 may form proximate the respective fractures 702, 704, 706, 708, and 710. Stress interference may occur between strain fields 712, 714, 716, 718, and 720 (as described in FIG. 3). In some implementations stress interference may occur between strain fields of other stages on the current wellbore and / or offset wellbores. For example, the stress interference, and therefore potential strain induced fracture fields, may occur in the region 722 between the strain field 720 and the strain field 730 of the first stage. Additionally, or alternatively, stress interference may occur between the strain fields 712, 714, 716, 718, and 720 and the strain fields of the stage hydraulically fractured on the wellbore 705.

[0037] FIG. 8 is a schematic depicting an example multi-well system, according to some implementations. The multi-well system 800 includes an overhead view of the horizontal section of three horizontal wellbores 801, 803, and 805 drilled in a subsurface formation. The wellbores 801, 803, and 805 may be similar to the wellbore 301, 303, and 305 described in FIG. 3. Similar to FIG. 4, after shutdown, fracturing fluid may no longer be injected into the subsurface formation. Accordingly, pressure in the fracture system may dissipate though the fracture system and / or pores within the subsurface formation, as depicted by the pressure response 802. The pressure response 802 of the fracture system pressure may interact in the region 808 with the pressure response 804 from the first stage and / or the pressure response 806 from the stage hydraulically fractured on the wellbore 805.

[0038] The multi-well systems described in FIGS. 3-9 may represent the method of a zipper frac completion. Management of the fracture system pressure within shear induced fracture fields may be applicable to all types of completions. For example, fracture system pressure management may be performed when an entire lateral of a wellbore has been or is currently being hydraulically fractured, multiple pads are being hydraulically fractured, multiple frac spreads are performing the hydraulic fracturing operations, etc.Example Operations

[0039] Examples operations are now described.

[0040] FIG. 9 is a flowchart depicting example operations for managing pressure of a fracture system, according to some implementations. FIG. 9 includes a flowchart 900 for obtaining measurements of a fracture system to identify strain induced fracture fields and utilizing the measurements to perform wellbore operations for managing the fracture system pressure and minimizing the wasted effective energy injected into the subsurface formation. The operations of the flowchart 900 are described in reference to the computer 170 of FIG. 1 and FIGS. 2-8. The operations of the flowchart 900 begin at block 902.

[0041] At block 902, the processor of the computer 170 may obtain, via one or more sensors, measurements of a fracture system while hydraulically fracturing one or more wellbores formed in a subsurface formation. The one or more sensors may include disposable fiber configured to obtain low frequency distributed acoustic sensing (LFDAS) strain measurements in the subsurface formation. The one or more sensors may include externally ported pressure gauges configured to obtain pressure measurements in the subsurface formation. In some implementations, pressure measurements may be derived from strain measurements obtained from fiber optic cables. For example, if only fiber optic cables are deployed in an offset wellbore, the strain measurements may be utilized to determine the pressure measurements of the subsurface formation. In some implementations, more than one externally ported pressure gauge may be positioned in the wellbore. For example, a first pressure gauge may be positioned at the heel of a horizontal wellbore and a second pressure gauge may be positioned at the toe of the horizontal wellbore. Any suitable number of externally ported pressure gauges may be positioned in the wellbore. One or more of the measurements may be obtained, and the use of strain, pressure, acoustic, etc. measurements described herein should not be viewed as limiting the use of sensor types.

[0042] The measurements may be obtained during hydraulic fracturing operations to monitor the fracture system growth and / or fracture system pressure of a fracture system in the subsurface formation. As fracturing fluid is injected into the subsurface formation via a wellbore, initial fractures (Mode 1 type failures) form due to the effective energy added to the system. In some implementations, there may be stress interference and / or pressure interference in the rock between the fractures, resulting in strain induced fracture fields comprising Mode 2 and / or Mode 3 type failures (as described in FIG. 2). The measurements may provide insight into the formation and dilation of the stress induced fracture fields during hydraulic fracturing operations.

[0043] In some implementations, the fracture system may be a part of a multi-well system. The multi-well system may include one or more wellbores on a single pad (i.e., single location on the Earth's surface where the respective wellheads of each wellbore are positioned), one or more wellbores from multiple pads, etc. where the wellbores may be in close proximity to each other to experience stress interference and hydraulic communication during the hydraulic fracturing operations performed on one or more of the wellbores.

[0044] The one or more sensors may be positioned downhole in one or more offset wellbores proximate the wellbore(s) being hydraulically fractured. For example, for a pad of multiple wells, while one or more of the wellbore are being hydraulically fractured, the other wells on the pad may include sensors positioned downhole to obtain strain and / or pressure measurements of the fracture system.

[0045] In some implementations, the measurements may indicate the generation and / or growth of shear induced fracture fields. To help illustrate, FIGS. 10A-10B are charts depicting measurements obtained during hydraulic fracturing operations, according to some implementations. FIG. 10A includes a chart 1000 with an x-axis 1002 and a y-axis 1004. The x-axis 1002 is the time having units in hours and minutes (HR:MIN). The y-axis is the ratio of pressure over temperature having units in pounds per square inch / degrees Fahrenheit (psi / degF). The curves 1090-1098 plotted into the chart 1000 may represent pressure / temperature measurements obtained from one or more sensors positioned in offset wellbores to the wellbore being hydraulically fractured. FIG. 10B includes a chart 1001 with an x-axis 1006 and a y-axis 1008. The x-axis 1006 is the time having units in hours and minutes (HR:MIN) and may be approximately similar to the x-axis 1002 of FIG. 10A. The y-axis is the depth having units in feet (feet). The color shade variation (such as area 1070 and area 1072) within the chart 1001 depicts strain measurements (in unitless measurements, inches / inches (in. / in.), etc.) that may be obtained via fiber optic cables positioned in one or more wells offset to the wellbore being hydraulically fractures. The measurements between the chart 1000 and chart 1001 may indicate open fractures in the rock, including open fractures and / or faults away from the initial fracture 1050 at approximately 16,750 feet.

[0046] The fracturing of the rock may begin when a ball sits on the frac plug to isolate the previous stage from the current stage and breakdown 1030 of the rock may begin. At breakdown 1030, energy may be injected into the subsurface formation to fracture the rock. At time period 11032, the energy may be great enough such that the initial fracture 1050 (Mode 1 type failure, in tension) forms in the rock. At time period 21034, the initial fracture 1050 dilates and fluid may begin to flow into the initial fracture 1050 and a pressure response may be observed (due to the increase in slope of the curves of FIG. 10A). At time period 31036 and time period 41038, pressure / temperature decreased in four of the offset wellbores (as shown in curves 1091, 1092, 1093, and 1094). Additionally, the strain measurements indicate the fracturing fluid has flowed to a point at approximately 11,995 feet (area 1070 and area 1072). The strain measurements aligning with change in pressure at time period 31036 and time period 41038 indicate a fault 1060 at approximately 11,995 feet may have been activated, where a significant strain event and / or a significant pressure event may have occurred such that the initial fracture 1050 is now hydraulically coupled with the fault 1060. Accordingly, the pressure (effective energy) applied to the subsurface formation may flow to the lower pressure field on the other side of the fault 1060, thus wasting the effective energy applied to the subsurface formation.

[0047] Returning to block 902, a target zone may be defined for where it may be desirable to place energy (such as a layer of rock in the subsurface formation, i.e., a reservoir) and an out-of-target zone where it may be desirable to limit the energy placement (such as layers above and below the target reservoir). In some implementations this may be done on a stage level, well level, across multiple stages / wells, reservoir level, etc. The deployed fiber optic cables may extend a full wellbore lateral, thus enabling energy related measurements (strain, pressure, etc.) across the target zone. The further away from the target zone energy may be measured, the likelihood of said energy may be wasted.

[0048] At block 904, the processor of the computer 170 may identify strain induced fracture fields based on the measurements. The strain induced fracture fields may be in regions of the subsurface formation between stages, between clusters, between wellbores, etc. where Mode 2 and / or Mode 3 type failures may have occurred. Events within the measurements may indicate strain induced fracture fields initiated and / or growing. Events may include pressure responses (as described in FIG. 10A), strain measurement variations (as described in FIG. 10B), a combination of events, etc. In some implementations, models such as machine learning models, physics based models, and / or a combination of the like, may be utilized to identify the strain induced fracture fields based on the measurements. For example, events that may be utilized to identify the in-target and out-of-target zone energy may be classified manually (i.e., by an analyst). Learning machines may be trained on strain data, pressure data, or any other suitable information relating to strain induced fracture field pressure management, pressure data, reservoir models, hybrid models, etc. Remaining events inside and / or outside of the target area may then be identified, quantified, and calculated as a function of distance, time, type of events, and characteristics of the events. Physics based models may include utilizing the compressibility factor to identify strain induced fracture fields and the point at which effective energy may be wasted.

[0049] Properties of the strain induced fracture fields may include the amount of Mode 2 and / or Mode 3 type failures within the strain induced fracture fields. As the amount of Mode 2 and / or Mode 3 type failures increase, the effective permeability of the subsurface formation may increase. Thus, the amount of Mode 2 and / or Mode 3 type failures may be accounted for when determining when to perform wellbore operations to avoid wasting energy put into the subsurface formation (as described below). In some implementations, the effective permeability may be sensitive to the pore pressure. As the pore pressure of the subsurface formation increases (due to injection of the fracturing fluid), the effective permeability may increase due to the fractures within the strain induced fracture field being open, potentially wasting energy. As the pressure decreases (such as when pumping stops and pressure dissipates), the fractures of the strain induced fracture field may begin to close and the effective permeability may also decrease.

[0050] At block 906, the processor of the computer 170 may determine a pressure ceiling of the fracture system. The pressure ceiling may be the pressure of the fracture system in which the energy injected into the fracture system is wasted. This pressure may be approximately similar to the overburden pressure of the subsurface formation (the weight of the rock above the subsurface formation). When the overburden pressure is exceeded, the fractures of the shear induced fracture field may dilate, allowing the pressure from the fracturing fluid to flow into lower-pressured regions in the rock until pressure is stabilized rather than generating new fractures and increasing the effective permeability of the rock. Overburden pressure may be determined by historical geological data, offset wellbore logs, pressure testing of wellbores in the multi-well system, etc.

[0051] The pressure ceiling may also be determined based on geological features proximate the wellbore such as faults. The pressure ceiling may be the pressure at which the fault is activated, as described in FIGS. 10A-10B. The increase in pore pressure of the subsurface formation may lubricate the fault, potentially activating the fault such that the fracture system pressure may dissipate to the fault resulting in wasted energy. In some implementations, fault activation may be identified via microsiesmic measurement.

[0052] In some implementations, the pressure ceiling may be region specific. For example, overburden pressure may be present in approximately all regions, but fault activation may only be present in specific regions. In some implementations, faults may not be present in regions proximate the wellbores being completed, and overburden pressure may be one or the main contributing factors to the pressure ceiling. In some implementations, the pore pressure for fault activation may only affect a portion of the fracture system. For example, a fault may be in hydraulic communication with stages near the toe of a wellbore (i.e., the end of the wellbore's lateral), but not be in hydraulic communication with stages near the heel of the wellbore (the beginning of the wellbore's lateral).

[0053] In some implementations, there may be a design factor implemented into the pressure ceiling. For example, the pressure ceiling may be a range of pressures, e.g., 10,000 pounds per square inch (psi) to 12,000 psi. Alternatively, the pressure ceiling may be a percentage of the critical value (such as the lesser value of the overburden pressure or the fault activation pressure if a fault is present), e.g., 90% of overburden pressure.

[0054] At block 908, the processor of the computer 170 may perform a wellbore operation to minimize the wasted effective energy put into the subsurface formation, via the hydraulic fracturing. As the fracture system pressure approaches the pressure ceiling, the pressure may leak into strain induced fracture fields rather than generate / grow new fractures, thus wasting the energy put into the subsurface formation. Accordingly, wellbore operations may be performed to minimize the wasted energy. Energy put into the rock may be determined based on factors including bottom hole pressure, pump rate, time, etc. For example, the bottom hole pressure multiplied by the pump rate of the fracturing fluid over a period of time may provide the energy put into the subsurface formation. In some implementations, the energy may be wasted when the pressure of the fracture system dissipates to regions due to strain induced fracture fields rather than generate new fractures to increase the effective permeability of the rock. Operations may include flowing offset wellbore that may be hydraulically coupled to the wellbore being hydraulically fractured, altering the sequence of completion, altering the completion design (such as volume pumped) as the fracture system pressure approaches the pressure ceiling, flowing a wellbore before hydraulically fracturing the next stage, repressuring depleted regions proximate the wellbore being hydraulically fractured, etc.

[0055] In some implementations, the strain induced fracture fields may be modeled prior to hydraulic fracturing operations. Thus, the model may be utilized during hydraulic fracturing operations when the measurements are obtained to perform the wellbore operations. Additionally, the model may be updated with the measurements. For example, measurements may be obtained on offset wellbores on the pad, offset wellbores from offset pads, etc. The measurements may be utilized to update the model to accurately predict when energy may be wasted as the fracture system pressure approaches the pressure ceiling and wellbore operations may be performed.

[0056] In some implementations, it may be desirable to hydraulically fracture multiple wellbores or simultaneously hydraulically fracture multiple wellbore pairs while obtaining measurements of the fracture system. One or more wellbore may be flowed to alleviate fracture pressure and avoid exceeding the pressure ceiling. In some implementations, the rate of the fracturing fluid being pumped into one or more wellbore during hydraulic fracturing operations may be larger than the rate the one or more offset wellbores may be flowing back. Accordingly, multiple stages may flow back from a single well when completed with a plug-and-perf completion method as the frac plugs may function as a check valve, allowing fluid to flow towards the heel of the wellbore.

[0057] In some implementations, modeling may be utilized to determine a completion design, stage sequence among a multi-well system. For example, a 10 wellbore pad with simulfrac may hydraulically fracture 3 stages per wellbore and then hydraulic fracturing operations may be routed to the next wellbore pair, allowing pressure control and flow back of the first three stages from the first wellbore pair until the full sequence of wellbore pairs has been hydraulically fractured for a predetermined number of stages. The pressure control may be performed on any wellbore pair within the multi-well system that is not undergoing hydraulic fracturing operations. In some implementations, the pad-level execution may be monitored with the measurements in real time, enabling control of how the energy is placed into the subsurface formation more efficiently. The sequence of wellbores to be fractured, the number of stages, flow rates, stage completion design, flow back volumes, flow back pressures, etc. may then be adjusted on a pad level basis based on the measurements and the pressure ceiling to optimize the energy placement. This may also be performed across multiple pads.

[0058] Fracture system pressure management at the pad level may intend to reduce energy dissipation outside target areas to reduce downhole pressure in order to generate better placement of effective energy for future stages. In some implementations, models may be generated (such as be supervised and / or unsupervised machine learning processes) where the objective may be to minimize out of zone energy events. The model output may be qualitative with the objective of quantifying the impact of sequential of hydraulic fracturing stages on a pad, flow back, pressure control, frac spread control on individual wellbores, across reservoir segments, etc. The objective may be to manage the out-of-target area energy to align with hydraulic fracturing targets (e.g., to minimize out-of-target energy and / or control energy boundaries) to influence ongoing hydraulic fracturing operations and / or release energy (bleed pressure) out of selected regions in order to efficiently use surface pumping pressure and / or rate for ongoing and / or future stages.

[0059] In some implementations, the measurements and pressure ceiling may be utilized for a full field development plan where all of the drilling and completion sequencing may to tied together to maximize asset value through management of the fracture system pressure.

[0060] In some implementations, the wellbore operation may include continuing with the hydraulic fracturing operations as planned. For instance, the measurements may indicate generation of Mode 2 and / or Mode 3 failures. However, the strain induced fracture fields may result in no wasted energy based on the measurements. Accordingly, the relative permeability of the subsurface formation may be increased due to the strain induced fracture fields with no negative consequences. Thus, operations may continue as planned until measurements indicate energy is being wasted due to the strain induced fracture fields.

[0061] While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. In general, techniques for managing pressure of strain induced fracture fields herein may be implemented with facilities consistent with any hardware system or hardware systems. Many variations, modifications, additions, and improvements are possible.

[0062] Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure.

[0063] Various modifications to the implementations described in this disclosure may be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other implementations without departing from the spirit or scope of this disclosure. Thus, the claims are not intended to be limited to the implementations shown herein but are to be accorded the widest scope consistent with this disclosure, the principles and the novel features disclosed herein.

[0064] Certain features that are described in this specification in the context of separate implementations also may be implemented in combination in a single implementation. Conversely, various features that are described in the context of a single implementation also may be implemented in multiple implementations separately or in any suitable subcombination. Moreover, although features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination may in some cases be excised from the combination, and the claimed combination may be directed to a subcombination or variation of a subcombination.

[0065] Similarly, while operations are depicted in the drawings in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed, to achieve desirable results. Further, the drawings may schematically depict one more example process in the form of a flow diagram. However, some operations may be omitted and / or other operations that are not depicted may be incorporated in the example processes that are schematically illustrated. For example, one or more additional operations may be performed before, after, simultaneously, or between any of the illustrated operations. In certain circumstances, multitasking and parallel processing may be advantageous. Moreover, the separation of various system components in the implementations described should not be understood as requiring such separation in all implementations, and the described program components and systems may generally be integrated together in a single software product or packaged into multiple software products. Additionally, other implementations are within the scope of the following claims. In some cases, the actions recited in the claims may be performed in a different order and still achieve desirable results.Example Computer

[0066] FIG. 11 is a block diagram depicting an example computer, according to some implementations. FIG. 11 depicts a computer 1100 for classification of system tracts. The computer 1100 includes a processor 1101 (possibly including multiple processors, multiple cores, multiple nodes, and / or implementing multi-threading, etc.). The computer 1100 includes memory 1107. The memory 1107 may be system memory or any one or more of the above already described possible realizations of machine-readable media. The computer 1100 also includes a bus 1103 and a network interface 1105. The computer 1100 can communicate via transmissions to and / or from remote devices via the network interface 1105 in accordance with a network protocol corresponding to the type of network interface, whether wired or wireless and depending upon the carrying medium. In addition, a communication or transmission can involve other layers of a communication protocol and or communication protocol suites (e.g., transmission control protocol, Internet Protocol, user datagram protocol, virtual private network protocols, etc.).

[0067] The computer 1100 also includes a signal processor 1111 and a controller 1115 which may perform the operations described herein. For example, the signal processor 1111 may obtain measurements of a fracture system, identify strain induced fracture fields within the subsurface formation based on the measurements, and determine a pressure ceiling of the fracture system. The controller 1115 may perform a wellbore operation based on strain induced fracture fields and the pressure ceiling. The signal processor 1111 and the controller 1115 can be in communication. Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and / or on the processor 1101. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor 1101, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in FIG. 11 (e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processor 1101 and the network interface 1105 are coupled to the bus 1103. Although illustrated as being coupled to the bus 1103, the memory 1107 may be coupled to the processor 1101.Example Implementations

[0068] Implementation #1: A method comprising: obtaining, via one or more sensors, measurements of a fracture system proximate one or more wellbores formed in a subsurface formation while hydraulically fracturing one or more wellbores; identifying one or more shear induced fracture fields within the fracture system based on the measurements; determining a pressure ceiling of the fracture system; and performing a wellbore operation to minimize wasted effective energy put into the subsurface formation, via the hydraulic fracturing, based on the shear induced fracture fields and the pressure ceiling.

[0069] Implementation #2: The method of Implementation #1, wherein the sensors include at least one of fiberoptic sensors and externally ported pressure gauges.

[0070] Implementation #3: The method of Implementation #1 or #2, wherein the measurements include at least one of strain and pressure.

[0071] Implementation #4: The method of any one or more of Implementation #1-3, wherein the one or more sensors are positioned in one or more offset wellbores proximate to the one or more wellbores being hydraulically fractured.

[0072] Implementation #5: The method of any one or more of Implementation #1-4, wherein the one or more shear induced fracture fields includes Mode 2 failures and Mode 3 failures.

[0073] Implementation #6: The method of any one or more of Implementation #1-5, wherein the one or more shear induced fracture fields are in regions of the subsurface formation including between clusters, between stages, and between wellbores.

[0074] Implementation #7: The method of any one or more of Implementation #1-6, wherein the pressure ceiling is determined based on overburden pressure or fault activation pressure.

[0075] Implementation #8: The method of any one or more of Implementation #1-7, wherein the wellbore operation includes increasing subsurface formation pressure in one or more regions, determining a sequence of completion, altering a hydraulic fracturing design prior to or during hydraulic fracturing operations, and flowing one or more offset wells prior to or during hydraulic fracturing operations of the one or more wellbores.

[0076] Implementation #9: A system comprising: one or more sensors; a processor; and a computer-readable medium having instructions stored thereon that are executable by the processor, the instructions including, instructions to obtain, via the one or more sensors, measurements of a fracture system proximate one or more wellbores formed in a subsurface formation while hydraulically fracturing one or more wellbores; instructions to identify one or more shear induced fracture fields within the fracture system based on the measurements; instructions to determine a pressure ceiling of the fracture system; and instructions to perform a wellbore operation to minimize wasted effective energy put into the subsurface formation, via the hydraulic fracturing, based on the shear induced fracture fields and the pressure ceiling.

[0077] Implementation #10: The system of Implementation #9, wherein the sensors include at least one of fiberoptic cables and externally ported pressure gauges.

[0078] Implementation #11: The system of Implementation #9 or #10, wherein the measurements include at least one of strain and pressure.

[0079] Implementation #12: The system of any one or more of Implementation #9-11, wherein the one or more sensors are positioned in one or more offset wellbores proximate to the one or more wellbores being hydraulically fractured.

[0080] Implementation #13: The system of any one or more of Implementation #9-12, wherein the one or more shear induced fracture fields includes Mode 2 failures and Mode 3 failures.

[0081] Implementation #14: The system of any one or more of Implementation #9-13, wherein the one or more shear induced fracture fields are in regions of the subsurface formation including between clusters, between stages, and between wellbores.

[0082] Implementation #15: The system of any one or more of Implementation #9-14, wherein the pressure ceiling is determined based on overburden pressure or fault activation pressure.

[0083] Implementation #16: The system of any one or more of Implementation #9-15, wherein the wellbore operation includes increasing subsurface formation pressure in one or more regions, determining a sequence of completion, altering a hydraulic fracturing design prior to or during hydraulic fracturing operations, and flowing one or more offset wells prior to or during hydraulic fracturing operations of the one or more wellbores.

[0084] Implementation #17: A non-transitory, computer-readable medium having instructions stored thereon that are executable by a processor, the instructions comprising: instructions to obtain, via one or more sensors, measurements of a fracture system proximate one or more wellbores formed in a subsurface formation while hydraulically fracturing one or more wellbores; instructions to identify one or more shear induced fracture fields within the fracture system based on the measurements; instructions to determine a pressure ceiling of the fracture system; and instructions to perform a wellbore operation to minimize wasted effective energy put into the subsurface formation, via the hydraulic fracturing, based on the shear induced fracture fields and the pressure ceiling.

[0085] Implementation #18: The non-transitory, computer-readable medium of Implementation #17, wherein the one or more shear induced fracture fields includes Mode 2 failures and Mode 3 failures.

[0086] Implementation #19: The non-transitory, computer-readable medium of Implementation #17 or #18, wherein the one or more shear induced fracture fields are in regions of the subsurface formation including between clusters, between stages, and between wellbores.

[0087] Implementation #20: The non-transitory, computer-readable medium of any one or more of Implementation #17-19, wherein the wellbore operation includes increasing subsurface formation pressure in one or more regions, determining a sequence of completion, altering a hydraulic fracturing design prior to or during hydraulic fracturing operations, and flowing one or more offset wells prior to or during hydraulic fracturing operations of the one or more wellbores.

[0088] Use of the phrase “at least one of” preceding a list with the conjunction “and” should not be treated as an exclusive list and should not be construed as a list of categories with one item from each category, unless specifically stated otherwise. A clause that recites “at least one of A, B, and C” can be infringed with only one of the listed items, multiple of the listed items, and one or more of the items in the list and another item not listed.

[0089] As used herein, the term “or” is inclusive unless otherwise explicitly noted. Thus, the phrase “at least one of A, B, or C” is satisfied by any element from the set {A, B, C} or any combination thereof, including multiples of any element.

Claims

1. A method comprising:obtaining, via one or more sensors, measurements of a fracture system proximate one or more wellbores formed in a subsurface formation while hydraulically fracturing one or more wellbores;identifying one or more shear induced fracture fields within the fracture system based on the measurements;determining a pressure ceiling of the fracture system; andperforming a wellbore operation to minimize wasted effective energy put into the subsurface formation, via the hydraulic fracturing, based on the shear induced fracture fields and the pressure ceiling.

2. The method of claim 1, wherein the sensors include at least one of fiberoptic sensors and externally ported pressure gauges.

3. The method of claim 1, wherein the measurements include at least one of strain and pressure.

4. The method of claim 1, wherein the one or more sensors are positioned in one or more offset wellbores proximate to the one or more wellbores being hydraulically fractured.

5. The method of claim 1, wherein the one or more shear induced fracture fields includes Mode 2 failures and Mode 3 failures.

6. The method of claim 1, wherein the one or more shear induced fracture fields are in regions of the subsurface formation including between clusters, between stages, and between wellbores.

7. The method of claim 1, wherein the pressure ceiling is determined based on overburden pressure or fault activation pressure.

8. The method of claim 1, wherein the wellbore operation includes increasing subsurface formation pressure in one or more regions, determining a sequence of completion, altering a hydraulic fracturing design prior to or during hydraulic fracturing operations, and flowing one or more offset wells prior to or during hydraulic fracturing operations of the one or more wellbores.

9. A system comprising:one or more sensors;a processor; anda computer-readable medium having instructions stored thereon that are executable by the processor, the instructions including,instructions to obtain, via the one or more sensors, measurements of a fracture system proximate one or more wellbores formed in a subsurface formation while hydraulically fracturing one or more wellbores;instructions to identify one or more shear induced fracture fields within the fracture system based on the measurements;instructions to determine a pressure ceiling of the fracture system; andinstructions to perform a wellbore operation to minimize wasted effective energy put into the subsurface formation, via the hydraulic fracturing, based on the shear induced fracture fields and the pressure ceiling.

10. The system of claim 9, wherein the sensors include at least one of fiberoptic cables and externally ported pressure gauges.

11. The system of claim 9, wherein the measurements include at least one of strain and pressure.

12. The system of claim 9, wherein the one or more sensors are positioned in one or more offset wellbores proximate to the one or more wellbores being hydraulically fractured.

13. The system of claim 9, wherein the one or more shear induced fracture fields includes Mode 2 failures and Mode 3 failures.

14. The system of claim 9, wherein the one or more shear induced fracture fields are in regions of the subsurface formation including between clusters, between stages, and between wellbores.

15. The system of claim 9, wherein the pressure ceiling is determined based on overburden pressure or fault activation pressure.

16. The system of claim 9, wherein the wellbore operation includes increasing subsurface formation pressure in one or more regions, determining a sequence of completion, altering a hydraulic fracturing design prior to or during hydraulic fracturing operations, and flowing one or more offset wells prior to or during hydraulic fracturing operations of the one or more wellbores.

17. A non-transitory, computer-readable medium having instructions stored thereon that are executable by a processor, the instructions comprising:instructions to obtain, via one or more sensors, measurements of a fracture system proximate one or more wellbores formed in a subsurface formation while hydraulically fracturing one or more wellbores;instructions to identify one or more shear induced fracture fields within the fracture system based on the measurements;instructions to determine a pressure ceiling of the fracture system; andinstructions to perform a wellbore operation to minimize wasted effective energy put into the subsurface formation, via the hydraulic fracturing, based on the shear induced fracture fields and the pressure ceiling.

18. The non-transitory, computer-readable medium of claim 17, wherein the one or more shear induced fracture fields includes Mode 2 failures and Mode 3 failures.

19. The non-transitory, computer-readable medium of claim 17, wherein the one or more shear induced fracture fields are in regions of the subsurface formation including between clusters, between stages, and between wellbores.

20. The non-transitory, computer-readable medium of claim 17, wherein the wellbore operation includes increasing subsurface formation pressure in one or more regions, determining a sequence of completion, altering a hydraulic fracturing design prior to or during hydraulic fracturing operations, and flowing one or more offset wells prior to or during hydraulic fracturing operations of the one or more wellbores.

Images