HYDRAULIC FRACTURING WITH DYNAMIC LOADING

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to and the benefit of U.S. Provisional Application No. 63/662,015, entitled “HYDRAULIC FRACTURING WITH DYNAMIC LOADING,” having a filing date of Jun. 20, 2024, the disclosure of which is incorporated herein by reference in its entirety.

FIELD

The present disclosure relates to the field of well completions and downhole operations. More particularly, the present disclosure relates to a hydraulic fracturing method and system.

BACKGROUND

This section is intended to introduce various aspects of the art, which may be associated with embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

During the drilling of a well, large diameter wellbores are cased leading to narrow diameter wellbores which are also cased, finally leading to the production zones in the reservoir. As each section is cased, cement is injected around the casing to hold it in place. The well is then completed by operations to begin the production of hydrocarbon fluids from the reservoir. The completions include the formation of perforations through the casing and cement of the final section into the reservoir using a perforation gun. Production tubing is then inserted down the wellbore into the production zone. The production tubing is used to extract hydrocarbons from the reservoir, with improved access to hydrocarbons provided by the use of hydraulic fracturing.

SUMMARY

An aspect of the disclosure provides a method of hydraulic fracturing. The method includes applying a dynamic load via a wellbore to primary fractures in a reservoir to generate the secondary fractures along the primary fractures. The method also includes extracting hydrocarbons from the wellbore via the secondary fractures in the reservoir.

Another aspect of the disclosure provides a well. The well includes a wellbore within a reservoir including a plurality of primary hydraulic fractures. The well also includes a dynamic loading device to generate secondary hydraulic fractures in the reservoir by applying a dynamic load to the primary fractures via the wellbore.

Another aspect of the disclosure includes a method for characterization of hydraulic fractures. The method includes generating hydraulic fractures using pressure pumping and proppant placement. The method also includes applying a dynamic load to the wellbore to generate a wellbore response. The method further includes characterizing the hydraulic fractures created using the pressure pumping and proppant placement based on the wellbore response.

DESCRIPTION OF THE DRAWINGS

The foregoing and other advantages of the present disclosure may become apparent upon reviewing the following detailed description and drawings of non-limiting examples in which:

FIG. 1A is a schematic view of a well including a conventional hydraulic fracture system;

FIG. 1B is a schematic view showing secondary fractures generated according to embodiments described herein;

FIG. 2 is a schematic view of hydraulic fracturing system that generates secondary fractures;

FIG. 3 is a graph depicting resonance frequency shifts;

FIG. 4 is a phase diagram depicting tensile failure in perfectly bonded layered rocks as a function of magnitude and frequency of the applied cyclic loading obtained using a finite element method (FEM) for different ratios of bedding thickness;

FIG. 5A is a graph depicting first principal stress calculated for a layered rock composite using an FEM for perfectly bonded layers;

FIG. 5B is a graph depicting first principal stress calculated for a layered rock composite using an FEM for layers with a finite interface strength;

FIG. 6 is a graph depicting geomechanical stress and sound speed over time from experiments on plugs taken from the extracted core sample of the first example unconventional reservoir;

FIG. 7 is a graph depicting permeability and storage porosity over time for the first example unconventional reservoir;

FIG. 8 is a graph depicting stress amplitude over strain amplitude for the first example unconventional reservoir;

FIG. 9 is diagram depicting an elemental map of the plug sample used in the geomechanical tests taken from the extracted core sample of the first example unconventional reservoir;

FIG. 10 is a graph depicting geomechanical stress and sound speed over time from experiments on plugs taken from the extracted core sample of the second example unconventional reservoir;

FIG. 11 is a graph depicting permeability and storage porosity over time for the second example unconventional reservoir;

FIG. 12 is a graph depicting stress amplitude over strain amplitude for the second example unconventional reservoir;

FIG. 13 is diagram depicting an elemental map of the plug sample used in the geomechanical tests taken from the extracted core sample of the second example unconventional reservoir;

FIG. 14 is a process flow diagram of a method for extraction of hydrocarbons using generated secondary fractures;

FIG. 15 is a process flow diagram of a method for extraction of hydrocarbons using iteratively generated secondary fractures;

FIG. 16 is a process flow diagram of a method for extraction of hydrocarbons using portioned hydraulic fracturing stages that generate secondary fractures;

FIG. 17 is a process flow diagram of a method for characterization of hydraulic fractures using a wellbore response to a dynamic load;

FIG. 18A is a graph of an example symmetric potential actuation;

FIG. 18B is a graph of an example asymmetric potential actuation;

FIG. 18C is a graph of another example asymmetric potential actuation;

FIG. 18D is a graph of an example full cycle potential actuation; and

FIG. 18E is a graph of an example square potential actuation.

It should be noted that the figures are merely examples of the present disclosure, and no limitations on the scope of the present disclosure are intended thereby. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the disclosure.

DETAILED DESCRIPTION

In the following detailed description section, the specific examples of the present disclosure are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present disclosure, this is intended to be for example purposes only and simply provides a description of the embodiments. Accordingly, the disclosure is not limited to the specific embodiments described below, but rather, include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

At the outset, and for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present disclosure are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or methods that serve the same or a similar purpose are considered to be within the scope of the present claims.

As used herein, the terms “a” and “an” mean one or more when applied to any embodiment described herein. The use of “a” and “an” does not limit the meaning to a single feature unless such a limit is specifically stated.

The terms “about” and “around” mean a relative amount of a material or characteristic that is sufficient to provide the intended effect. The exact degree of deviation allowable in some cases may depend on the specific context, e.g., ±1%, ±5%, ±10%, ±15%, etc. It should be understood by those of skill in the art that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numerical ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described are considered to be within the scope of the disclosure.

The term “Christmas tree” as used herein refers to an assembly of valves, spools, pressure gauges and chokes fitted to the wellhead of a completed well to control production. Christmas trees are available in a wide range of sizes and configurations, such as low- or high-pressure capacity and single- or multiple-completion capacity.

The term “coiled tubing” refers to a continuous length of small-diameter steel pipe and related surface equipment as well as associated drilling, completion and workover, or remediation, techniques.

As used herein, the terms “example,” exemplary,” and “embodiment,” when used with reference to one or more components, features, structures, or methods according to the present disclosure, are intended to convey that the described component, feature, structure, or method is an illustrative, non-exclusive example of components, features, structures, or methods according to the present disclosure. Thus, the described component, feature, structure or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, structures, or methods, including structurally and/or functionally similar and/or equivalent components, features, structures, or methods, are also within the scope of the present disclosure.

A “hydrocarbon” is an organic compound that primarily includes the elements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. As used herein, the term “hydrocarbon” generally refers to components found in natural gas, oil, or chemical processing facilities. Moreover, the term “hydrocarbon” may refer to components found in raw natural gas, such as CH₄, C₂H₂, C₂H₄, C₂H₆, C₃ isomers, C₄ isomers, benzene, and the like.

The term “tubing” refers to a wellbore tubular used to produce hydrocarbon fluids from a reservoir. Tubing may be production tubing through which the hydrocarbon fluid are received from the reservoir. Production tubing is assembled with other completion components to make up the “production string.” Tubing may also be injection tubing into which a slurry including hollow spheres may be injected to promote production.

The terms “well” and “wellbore” refer to holes drilled vertically, at least in part, and may also refer to holes drilled with deviated, highly deviated, and/or horizontal sections. The term also includes wellhead equipment, surface casing, intermediate casing, and the like, typically associated with oil and gas wells.

As used herein, a “well completion” is a group of equipment and operations that may be installed and performed to produce hydrocarbons from a subsurface reservoir. The well completion may include the casing, tubing, completion fluid, and other equipment used to prepare the well to produce hydrocarbons.

Overview

The present disclosure relates to a hydraulic fracturing system that uses secondary fractures to assist in the production of hydrocarbon fluids from a well. The secondary fractures are used to access more hydrocarbons via the primary fractures. In various embodiments, the hydraulic fracturing system provides various advantages over conventional hydraulic fracturing systems. For example, in one aspect of the disclosure, contact in unconventional reservoirs is increased through the secondary fractures created in layered reservoirs. The secondary fractures are the result of time-varying, or dynamic loads applied to primary bi-wing hydraulic fractures. Characteristics of effective dynamic loading (frequency, amplitude) are governed not only by characteristics of the target lithology but also by the wellbore infrastructure. The secondary fractures include bedding-parallel delaminations and bedding-perpendicular tensile cracks throughout the rock. The methods of the present disclosure can be applied to isolated stages (e.g. plug, perf, pressure pump, dynamic loading), several stages, or the entire wellbore, to maximize the creation of secondary fractures. Moreover, the dynamic load may be characterized by a broad range of frequencies (0.01-10 kilohertz (kHz)) and loading amplitudes (0.1-100 megaPascals (MPa)). In addition, the dynamic loading can be implemented using various methods, including pulse-generating devices (1-10 kHz) such as electrohydraulic fracturing, engineered devices like mechanically controlled flaps in the wellbore (0.01-10 Hz), chemical methods such as solid propellants and exothermic chemical reactions (0.01-100 Hz), proppant slugging, gas-liquid mixtures and/or controlled flow-rate changes in surface operations.

Another aspect of the present disclosure includes using the wellbore response to dynamic loading to characterize the volume of hydraulic fractures created during conventional pressure pumping and proppant placement.

FIG. 1A is a schematic view of a well 100 including a hydraulic fracturing system. The well 100 includes a wellbore 102 that passes through an unconventional reservoir that is composed of layered rock with bedding planes 104 that are parallel to the horizontal portion of wellbore 102. In various examples, the unconventional reservoir is composed of any combination of mudstones, shalestones, tight sands, carbonates, etc., that exhibit extremely low permeabilities. As shown in FIG. 1A, the unconventional reservoir naturally experiences static overburden (σ_V) 106, and horizontal (σ_H) 108 geomechanical stresses. The formation further includes two vertical bi-wing hydraulic fractures 110A and 110B. For example, the vertical bi-wing hydraulic fractures 110. These vertical bi-wing hydraulic fractures 110A and 110B have been artificially produced using any suitable method of hydraulic fracturing. For example, conventional hydraulic fracturing involves injecting (e.g., pressure pumping) large volumes of water/sand slurries at high pressures for extended periods (two-three hours) to create massive bi-wing primary fractures, such as the bi-wing fractures 110A and 110B. For example, the bi-wing primary fractures may be on the scale of hundreds of meters. However, due to the low permeability, oil is produced from a limited length scale adjacent to these fractures. Although unconventional oil and gas assets may be economically viable, the hydrocarbon recovery factor may be relatively lower to other hydrocarbon asset classes due to the low permeability, dominant production mechanics, and inability to contact more of the rock. Therefore, a majority of oil-in-place may be left behind using conventional hydraulic fracturing systems.

Therefore, a completion method as described herein may be used to access more producible hydrocarbon in the reservoir adjacent to the primary hydraulic fractures. In some embodiments, a process includes creating primary and secondary fractures in turn during each individual hydraulic fracturing stage. A stage includes focusing the stimulation operation on a portion (30-250′) of the horizontal wellbore (up to 10000′). Thus, after hydraulic fracturing is complete, the horizontal wellbore is intersected by many bi-wing primary fractures 110, as shown in FIG. 1A.

FIG. 1B is a schematic view showing secondary fractures generated according to embodiments described herein. FIG. 1B includes similarly referenced elements of FIG. 1A. In addition, the unconventional reservoir has been stimulated using varying pressures as shown in graph 112 in the primary hydraulic fractures 110A and 110B to generate secondary fractures including interface debondings 114 and layer failures 116.

In the embodiments in which primary and secondary hydraulic fractures are created in turn during each individual fracturing stage, stimulation of each stage involves two steps: (1) creating the primary bi-wing hydraulic fractures 110; and (2) applying a dynamic load in the primary hydraulic fractures 110A and 110B, exposing the fracture faces to a time varying force resulting in the formation of bedding parallel delaminations 114, and/or bedding perpendicular tensile cracks 116. In some instances, the combination and intersection of these secondary fractures may provide access very far into the reservoir. This may be especially true with internal delaminations that are not hydraulically connected to the primary hydraulic fractures 110A and 110B. After creating the secondary fractures, steps (1) and (2) are repeated at the next stage. In these embodiments, the process may include a single cycle of steps 1 and 2. Alternatively, in some embodiments, steps 1 and 2 may be repeated during a single fracturing stage. In various embodiments, the process may also be repeated throughout the formation of the primary hydraulic fracture, thus imposing the dynamic loads intermittently as the size of the primary bi-wing fracture increases.

Alternatively, in some embodiments, the conventional hydraulic fracturing operation providing primary hydraulic fractures 110A and 110B may be completed along the entire wellbore 102. Then, sections of the wellbore 102 are isolated for dynamic loading. In these embodiments, secondary cracks are created in-between the primary hydraulic fractures 110A and 110B in communication with the isolated wellbore section.

Although the example waveform of varying pressure used to generate secondary fractures as depicted in graph 112 is sinusoidal, any suitable variations of pressure/load may be used, as described in greater detail below. For example, the dynamic loading may be based on any of the potential actuations described in FIGS. 18A-18E, among other suitable potential actuations with sawtooth or standard or truncated waveforms. In addition, any number of additional wellbores may be included in well 100. Dynamic loading is intended to compliment the bi-wing primary hydraulic fractures 110A and 110B with secondary fractures in the form of bedding-parallel delaminations or debondings 114 and layer failures 116 including bedding-perpendicular tensile cracks in the interleaving rock between or adjacent to the primary hydraulic fractures 110A and 110B. The creation of these new permeability pathways thereby enhances hydrocarbon production by connecting the bi-wing hydraulic fractures 110A and 110B to more oil-bearing rock.

System for Generating Secondary Fractures

FIG. 2 is a high level schematic view of a hydraulic fracturing system 200 that generates secondary fractures. The system 200 includes similarly referenced components from FIGS. 1A and 1B. For example, the system 200 includes a wellbore 102 with a horizontal portion protruding into an unconventional reservoir. In addition, the system 200 includes a wellhead 202 coupled to the wellbore 102. In particular, the wellhead 202 shown in the example includes a Christmas tree assembly. In various embodiments, a time-varying load is applied to the wellhead 202 via the Christmas tree to impose a dynamic loading in the reservoir. The layered reservoir 204 includes two primary hydraulic fractures 206A and 206B. In the example of FIG. 2, the primary hydraulic fractures 206A and 206B are single-wing hydraulic fractures. A length 208 of the wellbore is measured from the wellhead 202 to the end 210 of the wellbore. In various embodiments, the length 208 of the isolated wellbore section may include a single stage, multiple stages, or the entire wellbore. In some examples, the end 210 may be packers used to isolate a portion of the wellbore 102 and thus change the length 208. In various embodiments, a dynamic loading is applied to the layered reservoir 204 via the primary hydraulic fractures 206A and 206B.

FIG. 3 is a graph 300 depicting resonance frequency shifts. The graph 300 shows that the half- to quarter-wave resonance frequency shifts when the hydraulic fracture volume (V_HF)>0, and the resonance frequency shifts below the quarter-wave resonance as the V_HF increases. In particular, the curve representing a hydraulic fracture volume to wellbore volume (V_WB) ratio (V_HF/V_WB) of 0.01 depicts the resonance frequency of a pipe with an extremely small, relative to the wellbore volume, volume of hydraulic fractures. This quarter wave resonance is based on the sound speed of the liquid in the wellbore and the length of the wellbore. The length of the wellbore in the example of FIG. 3 is 6,000 meters and the radius of the wellbore is 0.05 meters. The curves representing V_HF/V_WB ratios of 0.1 and 1 demonstrate that the larger volume of hydraulic fractures, the more the resonance frequency shifts to the left of the graph 300. Solid lines represent the pressure response relative to the pressure amplitude at the Christmas trees for each of the ratios, while dashed lines represent attenuation for each of the ratios. The peaks of each of the dashed curves represent the shifting resonance frequency of the well, which provides an upper limit on the spectral content of the dynamic loading waveform. In particular, the dynamic loading may avoid resonating the entire wellbore via the resonance frequency in order to prevent damage to the wellbore and its components. Accordingly, as described herein, energy may be concentrated using dynamic loading below the resonance frequency but above the static limit.

In one embodiment, dynamic loading exploits the lithology of layered unconventional rocks. Due to compositional variations during deposition, these rocks are interbedded, and the bedding interfaces are often weaker than the rock. In addition, the layers have different elastic and viscoelastic mechanical properties. As a result, dynamic loading at the surface of the primary fracture faces, which are perpendicular to the rock layers, enables the accumulation of differential strain between the layers. This differential strain produces deleterious stresses that either delaminate the interfaces, or break the rock. This is akin to a fatigue-induced weakening, or softening, that depends on the characteristics of the dynamic load and the depositional history of the reservoirs. In various examples, the efficacy of the dynamic loading depends on the characteristics of the time varying load, the interbedding, and the engineering infrastructure in-place to impose these conditions. For example, the wellbore behaves like a resonator, where the resonant frequency is dictated by the wellbore length and the boundary conditions. This resonance imposes limits on the frequency content of the time varying wellbore pressure. The most important characteristic of the wellbore is the wellbore length (L). In particular, when the wellbore is not in communication with a primary hydraulic fracture the system exhibits a half wave resonance, where the resonance frequency, f_R, is the sound speed (c) in the fluid that fills the wellbore divided by 2 L, per the equation:

f R = c / 2 ⁢ L ( Eq . 1 )

For example, the sound speed c in water is ˜1500 meters per second (m/s). However, when the wellbore is in communication with a hydraulic fracture, the resonance shifts towards a quarter wave resonance, per the equation:

fR = c / 4 ⁢ L ( Eq . 2 )

In addition, as the volume, or scale, of hydraulic fractures increases, the resonance may shift below the quarter wave resonance. In some embodiments, this behavior may be exploited to infer something about the volume of hydraulic fractures created during a single stage, or in communication with a segment of the wellbore. Therefore, characterizing the frequency dependent response of the wellbore before and after conventional hydraulic fracturing represents another aspect of the present disclosure that involves applying a dynamic load at the wellhead. For example, the dynamic load may be a continuous, or discrete impulsive, forcing of liquid at the wellhead.

FIG. 4 is a phase diagram 400 depicting tensile failure in perfectly bonded layered rocks as a function of magnitude and frequency of the applied cyclic loading obtained using a finite element method (FEM) for different ratios of bedding thickness. In particular, the minimal frequencies for tensile failure were obtained using FEM for different ratios of the bedding heights of compliant (h_c) and stiff layers (h_s), including h_s/h_c ratios of 1, 2, 3, 4, and 5. The viability of dynamic loading was assessed using finite-element simulations for the model system highlighted by the dashed box in FIG. 1A. The initial model assumed perfectly bonded rock layers with contrasting mechanical/viscoelastic properties, as shown in FIGS. 5A and 5B. In FIGS. 5A and 5B, the thicker layers represent shale (more compliant/viscous), and the thinner layer represents calcite (less compliant/viscous). The mechanical properties of the layers were determined using nanoindentation testing of complaint and stiff rock samples from unconventional reservoirs, as shown in Table 1:

TABLE 1
Viscoelastic parameters chosen for compliant and stiff
layers of composite layer model in FEM simulations

	E0 (GPa)	E1 (GPa)	E2 (GPa)	E3 (GPa)	τ1 (sec)	τ2 (sec)	τ3 (sec)

Compliant	11.4	266	303	277	0.45	5.2	162
Stiff	93.2	1494	2156	—	0.79	14.1	—

The parameters in Table 1 were obtained by fitting Generalized Kelvin-Voigt model to creep data obtained using nanoindentation testing of rock samples from unconventional rocks. In the initial model, a static overburden, σ_V, and horizontal, σ_h, stress were imposed. The latter corresponds to an altered minimum horizontal stress due to the primary hydraulic fracture. In addition to the imposition of this static in-situ stress state, an oscillatory horizontal load was applied along the face of the primary fracture, F_h(t), characterized by a single frequency. Therefore, the total load acting in the horizontal direction was σ_h+F_h(t), and as indicated, F_h(t) was the only time varying load. Applying dynamic loads to tightly bonded layers with contrasting mechanical/viscoelastic properties was shown to induce deleterious stresses in the matrix between the primary fractures.

FIG. 5A is a graph 500A depicting first principal stress calculated for a layered rock composite using FEM for perfectly bonded layers. The graph 500A includes a horizontal axis depicting half-length of primary fractures in feet and a vertical axis representing layer thickness in feet. The left and bottom edges of graph 500A have a zero-displacement symmetry boundary condition (BC), whereas a vertical stress (e.g., overburden, ov) is being applied at the top edge, and a constant horizontal stress at the right edge (Oh). In addition, an oscillatory load (the dynamic load in primary hydraulic fracture) is applied laterally at the right edges of graphs 500A and 500B.

In perfectly bonded layers, the interface strength is assumed to be greater than the strength of the rock. As shown in the circled portion of graph 500A, layers with strong interfaces tend to fail via tensile failure. For example, FIG. 5A shows the first principal stress obtained for a tightly bonded layered rock subjected to a vertical overburden stress, σ_V=70 MPa and a horizontal stress, σ_h=63 MPa. The horizontal dynamic load applied to the layered rock is F_h=10 MPa, with frequency, f=0.5 Hz. Regions with high tensile stresses, and undergoing tensile failure as determined by the Griffith criterion, first introduced by Griffith et al. in 1924, are marked by an oval. The arrows, which indicate the direction of the first principal stress, are oriented along the direction of tensile failure. Repeating the calculation for various combinations of frequency and amplitude yielded the phase diagram outlining the tensile failure envelop for tightly bonded layers shown in FIG. 4. It was observed that the magnitude of the force and the frequency required to induce damage in the layers between the primary fractures are inversely related. As shown in FIGS. 4 and 5A, tensile failure can occur at frequencies >0.01 Hz and for amplitudes >300 psi. This provides confidence that the methods of the present disclosure are practical because cyclical loading of similar frequency and amplitude has already been observed in a well bore (e.g., during sudden shut-in) and could easily be imposed to isolated portions of the wellbore using conventional technology including conventional pressure pumping equipment, such as coiled tubing, or even more easily using newer technology powered by jet engines, and coupled to sophisticated infrastructure for handling high electrical power that is significantly more responsive than conventional diesel powered hydraulic pumps.

FIG. 5B is a graph 500B depicting first principal stress calculated for a layered rock composite using FEM for layers with a finite interface strength. The graph 500B similarly includes a horizontal axis depicting half-length of primary fractures in feet and a vertical axis representing layer thickness in feet. In the example of FIG. 5B, the tensile strength of the interface was assumed to be 10 MPa. As shown in the circled portion of graph 500B, layers with a weak interface failed via delamination. When the layers in the previously described simulation were given a finite cohesive strength, a shear failure was observed at the interface. In particular, a dynamic load (F_h=2 MPa, with frequency, f=10 Hz) was applied laterally in addition to the horizontal stress. A shear failure in the form of delamination of the layers was observed with the application of the dynamic load. The delamination of the layers is further confirmed by the compressive first principal stresses observed in the debonded layers and the orientation of the first principal stress, indicated by the arrows.

FIG. 6 is a graph 600 depicting geomechanical stress and sound speed over time from experiments on plugs taken from the extracted core sample of the first example unconventional reservoir. The confining (green curve) and dynamic axial (blue) curve are meant to mimic dynamic loading imposed on the face of a primary hydraulic fracture. The various sound speed measurements reflect dynamic mechanical stiffnesses that may be monitored using compressional and shear waves with various polarizations. Graph 600 includes a horizontal axis representing time and a vertical axis representing both stress and sound speed.

FIG. 7 is a graph 700 depicting permeability and storage porosity over time for the first example unconventional reservoir. Graph 700 includes a horizontal axis representing time and a vertical axis representing both permeability and storage porosity. As shown in graph 700, permeability of the sample increases due to the reduced confining stress shown in graph 600.

FIG. 8 is a graph 800 depicting stress amplitude over strain amplitude for the first example unconventional reservoir. Graph 800 corresponds to the difference between the axial and confining stress of 21 MPa observed after 12,000 s in graph 600.

FIG. 9 is diagram depicting an elemental map 900 of the plug sample used in the geomechanical tests taken from the extracted core sample of the first example unconventional reservoir. The elemental map represents a mixture of calcium (Ca), silicon (Si), carbon (C), sulfur(S), and aluminum (Al), represented by different shades/colors on the elemental map 900. The elemental map 900 depicts a largely uniform elemental composition throughout the sample. A fracture 902 is seen near the top of the sample.

FIG. 10 is a graph 1000 depicting geomechanical stress and sound speed over time from experiments on plugs taken from the extracted core sample of the second example unconventional reservoir. The confining (green curve) and dynamic axial (blue) curve are meant to mimic dynamic loading imposed on the face of a primary hydraulic fracture. The various sound speed measurements reflect dynamic mechanical stiffnesses that may be monitored using compressional and shear waves with various polarizations. Graph 1000 includes a horizontal axis representing time and a vertical axis representing both stress and sound speed. In this case the longitudinal sound speed polarized perpendicular to the bedding planes shows a slight reduction due to dynamic loading.

FIG. 11 is a graph 1100 depicting permeability and storage porosity over time for the second example unconventional reservoir. Similar to graph 700 of FIG. 7, graph 1100 includes a horizontal axis representing time and a vertical axis representing both permeability and storage porosity. As shown in graph 1100, permeability and storage porosity of the sample increases when the dynamic loading begins for the two lowest confining stresses.

FIG. 12 is a graph 1200 depicting stress amplitude over strain amplitude for the second example unconventional reservoir. Graph 1200 corresponds to the difference between the axial and confining stress of 3.7 MPa observed between 0-4000 seconds in 1000. The sample exhibits much more hysteresis relative to the hysteresis shown in 800 of FIG. 8.

FIG. 13 is diagram depicting an elemental map 1300 of the plug sample used in the geomechanical tests taken from the extracted core sample of the second example unconventional reservoir. Similar to the elemental map 1000 of FIG. 10, the elemental map represents a mixture of calcium (Ca), silicon (Si), carbon (C), sulfur(S), and aluminum (Al), represented by different shades/colors on the elemental map 1300. However, the mixture of elemental map 1000 has a non-uniform composition. For example, the sample may be a carbonated mudstone with alternating carbonate and silicate layers. The upper layers of the elemental map 1300 is mostly composed of calcium and carbon, while the lower layers contain more silicon.

Methods for Generating Secondary Fractures Using Dynamic Loading

FIG. 14 is a process flow diagram of a method 1400 for extraction of hydrocarbons using generated secondary fractures. The method 1400 is implemented by a hydraulic fracturing system, such as the hydraulic fracturing system 200 described with respect to FIG. 2.

The method 1400 begins at block 1402, in which a dynamic load is applied via a wellbore to primary fractures in reservoir to generate secondary fractures along the primary fractures. For example, the dynamic load can be applied by oscillating the pressure in the wellbore, causing the primary fractures to open and close under the oscillating pressure. In various embodiments, any suitable method for oscillating pressure may be used, such as mechanical, chemical, thermal, or explosive methods. In various examples, the secondary fractures include bedding-parallel delaminations, bedding-perpendicular tensile cracks, or a combination thereof. In some embodiments, the dynamic load is applied using a pulse-generating device. For example, the dynamic load can be applied via an electrohydraulic fracturing device to oscillate pressure in the wellbore. In some embodiments, the dynamic load is applied using an engineered device, such as a mechanically controlled flap in the wellbore. In some embodiments, the dynamic load is applied using a solid propellant and exothermic reaction. In some embodiments, the dynamic load is applied using proppant slugging. In some embodiments, the dynamic load is applied using controlled flow-rate changes in surface operations. In some embodiments, the dynamic load is applied using coiled tubing. For example, gases or liquids of varying density may be injected via the coiled tubing in order to apply the dynamic load. In various embodiments, a frequency of the applied dynamic load is within the range of 0.01 to 10 kilohertz. In various embodiments, an amplitude of the applied dynamic load is within the range of 0.1 to 100 MPa. In various embodiments, the frequency or amplitude of the applied dynamic load may be based on a length of the wellbore or a characteristic of a target lithology of the reservoir, or both. Moreover, the waveform of the dynamic loading may be any suitable form, such as sinusoidal, truncated triangle, square. In addition, in some embodiments, a single frequency may be used. Alternatively, in some embodiments, waveforms having multiple frequencies may be used for dynamic loading.

At block 1404, hydrocarbons are extracted from the wellbore via the secondary fractures in the reservoir. For example, the hydrocarbons may be extracted from the secondary fractures into the primary fractures, through the wellbore into the wellhead.

The process flow diagram of FIG. 14 is not intended to indicate that the steps of the method 1400 are to be executed in any particular order, or that all of the steps of the method 1400 are to be included in every case. Further, any number of additional steps not shown in FIG. 14 may be included within the method 1400, depending on the details of the specific implementation. For example, the method 1400 can include generating the primary fractures in the reservoir, as described in FIGS. 15 and 16 below.

FIG. 15 is a process flow diagram of a method 1500 for extraction of hydrocarbons using iteratively generated secondary fractures. The method 1500 is implemented by a hydraulic fracturing system, such as the hydraulic fracturing system 200 described with respect to FIG. 2.

The method 1500 begins at block 1502, a hydraulic fracturing is initiated along entire length of wellbore to generate primary fractures in reservoir.

At block 1504, a section of the wellbore is isolated for dynamic loading. For example a section of the wellbore can be isolated using coiled tubing and packers straddled on either side of the coiled tubing.

At block 1506, a dynamic load is applied via isolated section of wellbore to adjacent primary fractures in reservoir to generate secondary fractures in reservoir.

At decision diamond 1508, a determination is made as to whether an additional section of the wellbore is to be isolated. If another section of the wellbore is to be isolated for fracturing, then the method continues at 1504, where the additional section is isolated for dynamic loading. If another section of the wellbore is not to be isolated, then the method proceeds to block 1404.

At block 1404, hydrocarbons are extracted from the secondary fractures in reservoir via wellbore. For example, the hydrocarbons may be extracted from the secondary fractures into the primary fractures, through the wellbore into the wellhead.

The process flow diagram of FIG. 15 is not intended to indicate that the steps of the method 1500 are to be executed in any particular order, or that all of the steps of the method 1500 are to be included in every case. Further, any number of additional steps not shown in FIG. 15 may be included within the method 1500, depending on the details of the specific implementation.

FIG. 16 is a process flow diagram of a method 1600 for extraction of hydrocarbons using portioned hydraulic fracturing stages that generate secondary fractures. The method 1600 is implemented by a hydraulic fracturing system, such as the hydraulic fracturing system 200 described with respect to FIG. 2.

The method 1600 begins at block 1602, a hydraulic fracturing is focused along portion of a wellbore to generate primary fractures in an adjacent portion of reservoir. For example, the primary fractures may be bi-wing hydraulic fractures perpendicular to a horizontal portion of the wellbore.

At block 1604, a dynamic load is applied to portion of wellbore to generate secondary fractures along primary fractures of reservoir. For example, the secondary fractures may include bedding-parallel delaminations, bedding-perpendicular tensile cracks, or a combination thereof.

At decision diamond 1606, a determination is made as to whether an additional stage of fracturing remains. If another stage of fracturing remains, then the method 1600 continues at block 1602, where hydraulic fracturing is focused on another portion of the wellbore for the additional stage of fracturing. If another stage of fracturing does not remain, then the method 1600 continues at block 1404.

At block 1404, hydrocarbons are extracted from the secondary fractures in reservoir via wellbore. For example, the hydrocarbons may be extracted from the secondary fractures into the primary fractures, through the wellbore into the wellhead.

The process flow diagram of FIG. 16 is not intended to indicate that the steps of the method 1600 are to be executed in any particular order, or that all of the steps of the method 1600 are to be included in every case. Further, any number of additional steps not shown in FIG. 16 may be included within the method 1600, depending on the details of the specific implementation.

Method for Characterizing Primary Fractures Using Dynamic Loading

FIG. 17 is a process flow diagram of a method 1700 for characterization of hydraulic fractures using a wellbore response to a dynamic load. The method 1700 is implemented by a hydraulic fracturing system, such as the hydraulic fracturing system 200 described with respect to FIG. 2.

The method 1700 begins at block 1702, hydraulic fractures are generated using conventional pressure pumping and proppant placement. In various examples, the hydraulic fractures are generated in communication with a portion of the wellbore or along the entire wellbore.

At block 1704, a dynamic load is applied to the wellbore to generate a wellbore response. For example, the wellbore response may include a frequency-dependent response.

At block 1706, the hydraulic fractures created using pressure pumping and proppant placement are characterized based on the wellbore response. For example, the volume of the hydraulic fractures created using conventional pressure pumping and proppant placement based on the wellbore response.

The process flow diagram of FIG. 17 is not intended to indicate that the steps of the method 1700 are to be executed in any particular order, or that all of the steps of the method 1700 are to be included in every case. Further, any number of additional steps not shown in FIG. 17 may be included within the method 1700, depending on the details of the specific implementation. For example, the dynamic load of block 1704 may also be applied before the hydraulic fractures are generated at block 1702 to provide a wellbore response to compare with the wellbore response after the hydraulic fractures are generated at block 1702.

Example Dynamic Loading Waveforms

FIG. 18A is a graph 1800A of an example symmetric potential actuation. The shape of the wave is a truncated triangular waveform, which takes the form of a trapezoid. The example symmetric potential actuation in graph 1800A optimizes t1, c2, c3 constrained by operational limits. With the symmetric potential actuation of FIG. 18A, given a wellbore length of 6,100 meters, the quarter wave given by the inverse of Eq.1 is 0.39 radians/second. The spectral density of actuation profile of graph 1800A is described using the equation:

F ⁡ ( ω ) = A ⁡ ( c 2 - c 2 ⁢ e - it 1 ⁢ ω + e - ic 2 ⁢ t 1 ⁢ ω - e - ic 3 ⁢ t 1 ⁢ ω + c 3 ( e - it 1 ⁢ ω - 1 ) ) ( c 2 - c 3 ) ⁢ t 1 ⁢ ω 2 ( Eq . 3 )

The resulting spectral density graph (not shown) shows various spikes associated with the quarter wave. However, the energy in the vicinity of the static limit is reduced.

FIG. 18B is a graph 1800B of an example asymmetric potential action. The spectral density of actuation profile of graph 1800B is described using Eq. 3 above. The resulting spectral density graph (not shown) shows the various spikes associated with the quarter wave reduced to smoother valleys. Thus, asymmetry in the dynamic loading curve flattens the spectral density of actuation.

FIG. 18C is a graph 1800C of another example asymmetric potential actuation. The spectral density of actuation profile of graph 1800C is also described using Eq. 3 above. The resulting spectral density graph (not shown) shows the various spikes associated with the quarter wave was also reduced to smoother valleys. Again, asymmetry in the dynamic loading curve flattens the spectral density of actuation, regardless of the type of asymmetry.

FIG. 18D is a graph 1800D of an example full cycle potential actuation. As one example, a total cycle time may be 24 seconds, with an increase over four seconds, a stable plateau of four seconds, a decrease over eight seconds, a stable trough for four seconds, and increase back over four seconds to the initial value. The spectral density of actuation profile of graph 1800D is described using the equation:

F ⁡ ( ω ) = - Sum ( c 2 - c 3 ) ⁢ ( c 4 - c 5 ) ⁢ t 1 ⁢ ω 2 ( Eq . 4 ) where : Sum = A ⁡ ( 2 ⁢ ( c 4 - c 5 ) ⁢ e - i ⁡ ( c 2 + c 3 ) ⁢ t 1 ⁢ ω ( e - ic 2 ⁢ t 1 ⁢ ω + e - ic 3 ⁢ t 1 ⁢ ω ) + c 3 ( c 5 - c 5 ⁢ e - it 1 ⁢ ω + e - ic 4 ⁢ t 1 ⁢ ω - e - ic 5 ⁢ t 1 ⁢ ω + c 4 ( e - it 1 ⁢ ω - 1 ) ) + c 2 ( c 4 - c 4 ⁢ e - it 1 ⁢ ω - e - ic 4 ⁢ t 1 ⁢ ω + e - ic 5 ⁢ t 1 ⁢ ω + c 5 ( e - it 1 ⁢ ω - 1 ) ) ) ( Eq . 5 )

The resulting spectral density graph (not shown) demonstrates that a full cycle concentrates power below a critical frequency, such as the resonance frequency of the wellbore.

FIG. 18E is a graph 1800E of an example square potential actuation. In various embodiments, square wave forms of different duration and spacing may be used to achieve power spectrums.

While the present disclosure may be susceptible to various modifications and alternative forms, the example examples discussed above have been shown only by way of example. However, it should again be understood that the present disclosure is not intended to be limited to the particular examples disclosed herein. Indeed, the present disclosure includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.