US20160032654A1

US20160032654A1 - Encapsulated explosives for drilling wellbores

Info

Publication number: US20160032654A1
Application number: US14/377,385
Authority: US
Inventors: Kazi Rashid; David Wayne Cawthon
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2013-08-27
Filing date: 2013-08-27
Publication date: 2016-02-04
Also published as: CN105378216A; GB2532884A; WO2015030732A1; GB201600217D0; DE112013007387T5; CA2917846C; AR096676A1; CA2917846A1

Abstract

Systems and methods for drilling operations may use encapsulated explosives to complement the performance of downhole cutting tools. An exemplary method may include drilling a wellbore penetrating a subterranean formation with a downhole cutting tool; circulating a drilling fluid in the wellbore, wherein the drilling fluid comprises a base fluid and an encapsulated explosive having an average diameter of about 10 nm to about 20 microns; triggering detonation of the encapsulated explosive; and detonating the encapsulated explosive proximal to a portion of the subterranean formation adjacent the downhole cutting tool.

Description

BACKGROUND

The exemplary embodiments described herein relate to systems and methods for drilling operations that use encapsulated explosives to complement the performance of downhole cutting tools.
Downhole cutting tools are commonly used to drill wellbores into subterranean formations in the oil and gas industry. Typical drilling action associated with downhole cutting tools includes cutting elements that penetrate or crush adjacent formation materials and remove the formation materials using a scraping action. Drilling fluid circulated during drilling may also be provided to perform several functions including washing away formation materials and other downhole debris from the bottom of a wellbore, cleaning associated cutting structures and carrying formation cuttings radially outward and then upward to an associated well surface.
The rate of penetration of the downhole cutting tool is one measure of drilling efficiency. As the rate of penetration is increased, the abrasive wear of the downhole cutting tool increases. Wearing of the downhole cutting tool necessitates periodic replacement of the downhole cutting tool. Replacement involves ceasing drilling operations, tripping the worn downhole cutting tool to the surface and subsequently tripping a new or refurbished downhole cutting tool into place within the wellbore. Accordingly, replacing a downhole cutting tool can be quite a costly and time-consuming process.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of the exemplary embodiments described herein, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to those skilled in the art and having the benefit of this disclosure.

FIG. 1 illustrates a system suitable for drilling a wellbore penetrating a subterranean formation

FIGS. 2A and 2B illustrate a drill bit in a top view and a cross-sectional view, respectively, that includes a sonicator for triggering the encapsulated explosives described herein according to at least one embodiment described herein.

FIG. 3 illustrates a reamer that includes hardware for triggering the encapsulated explosives described herein according to at least one embodiment described herein.

FIG. 4 illustrates a drill bit and a portion of a drill string with a reservoir of the encapsulated explosives described herein.

DETAILED DESCRIPTION

The exemplary embodiments described herein relate to systems and methods for drilling operations that use encapsulated explosives to complement the performance of downhole cutting tools.
In one aspect, the disclosed systems and methods relate to drilling operations that include various particular uses of encapsulated explosives that can be triggered to detonate proximal to a portion of a subterranean formation at or near a downhole cutting tool. The detonation weakens and/or breaks the adjacent subterranean formation, which may complement the actions of the downhole cutting tool. In turn, an increased rate of penetration may be achieved with less torque and energy consumption and less downhole cutting tool wear. As a result, well operators may benefit from decreases in the cost and time of drilling operations.
As used herein, the term “downhole cutting tool” refers to downhole tools capable of drilling at least a portion of a wellbore penetrating a subterranean formation. Examples of downhole cutting tools include, but are not limited to, polycrystalline diamond compact (“PDC”) bits, drag bits, impregnated bits, roller cone bits, reamers with cutting elements, and the like.
FIG. 1 illustrates an exemplary system that may implement the principles of the present disclosure, according to one or more embodiments. As illustrated, a drill rig 100 uses sections of pipe 102 (sometimes referred to as drill string) to transfer rotational force to a downhole cutting tool 104 and a pump 106 may be used to circulate drilling fluid (shown as flow arrows A) to the bottom of the wellbore through the sections of pipe 102. As the downhole cutting tool rotates, the applied weight-on-bit (“WOB”) forces various cutting elements of the cutting tool 104 into the formation being drilled. Thus, the cutting elements apply a compressive stress that exceeds the yield stress of the formation, thereby grinding through the formation. The resulting fragments (also referred to as “cuttings”) are flushed away from the cutting face by a high flow of the drilling fluid (also referred to as “mud”). According to embodiments described herein, encapsulated explosives may be included in the drilling fluid and triggered so as to detonate proximal to a portion of the formation being penetrated by the downhole cutting tool 104.
Detonating the encapsulated explosives downhole may lower the yield stress of the formation adjacent the downhole cutting tool 104, thereby allowing for more efficient drilling operations and prolonging the lifetime of the cutting tool 104.
As used herein, the term “encapsulated explosive” refers to an explosive composition substantially encased by another composition. Examples of encapsulated explosives may include, but are not limited to, explosive compositions substantially encased by a micelle, a liposome, a crosslinked liposome, a polymeric vesicle, a dendritic polymer, a polymeric coating, a mesoporous metal oxide particle, and any hybrid thereof. Additional examples of encapsulated explosives may include, but are not limited to, coated nanoparticles, coated microparticles, impregnated mesoporous metal oxide nanoparticles, impregnated mesoporous metal oxide microparticles, and the like. Drilling fluids described herein may include, in some embodiments, combinations of any of the foregoing encapsulated explosives.
Examples of explosive compositions may include, but are not limited to, thermite, octogen, pentaerythritol tetranitrate, tetranitrotoluene, an explosive nitroamine, lead picrate, mercury fulminate, nitrogen triiodide, potassium perchlorate, ammonium perchlorate, and the like, and a combination thereof. In some instances, the explosive composition may be a binary explosive where each component of the binary explosive are individual encapsulated explosives (i.e., comprising a plurality of first encapsulated components and a plurality of second encapsulated components). Examples of binary explosive compositions may include, but are not limited to, ammonium nitrate/fuel oil, ammonium nitrate/nitromethane, ammonium nitrate/aluminum, and nitroethane/physical sensitizer.
In some embodiments, encapsulated explosives described herein may have an average diameter ranging from a lower limit of about 10 nm, 50 nm, 100 nm, or 500 nm to an upper limit of about 20 microns, 10 microns, 5 microns, 1 micron, or 500 nm, and wherein the average diameter may range from any lower limit to any upper limit and encompasses any subset therebetween. As used herein, the term “average diameter” refers to the number mean diameter along the smallest dimension. For example, an encapsulated explosive that is a coated nanorod with a length of about 50 nm and having an aspect ratio of five would, as described herein, have a diameter of about 10 nm.
Mixtures of encapsulated explosives, which differ by size and/or composition, may be useful in tailoring the intensity of the explosions downhole.
Suitable base fluids may include, but are not limited to, oil-based fluids, aqueous-based fluids, aqueous-miscible fluids, water-in-oil emulsions, or oil-in-water emulsions. One skilled in the art with the benefit of this disclosure should recognize that the base fluid should be chosen to be compatible with at least the encapsulated explosive and the triggering methods described herein. Suitable oil-based fluids may include alkanes, olefins, aromatic organic compounds, cyclic alkanes, paraffins, diesel fluids, mineral oils, desulfurized hydrogenated kerosenes, and any combination thereof. Suitable aqueous-based fluids may include fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), seawater, and any combination thereof. Suitable aqueous-miscible fluids may include, but not be limited to, alcohols (e.g., methanol, ethanol, n-propanol, isopropanol, n-butanol, sec-butanol, isobutanol, and t-butanol), glycerins, glycols (e.g., polyglycols, propylene glycol, and ethylene glycol), polyglycol amines, polyols, any derivative thereof, any in combination with salts (e.g., sodium chloride, calcium chloride, calcium bromide, zinc bromide, potassium carbonate, sodium formate, potassium formate, cesium formate, sodium acetate, potassium acetate, calcium acetate, ammonium acetate, ammonium chloride, ammonium bromide, sodium nitrate, potassium nitrate, ammonium nitrate, ammonium sulfate, calcium nitrate, sodium carbonate, and potassium carbonate), any in combination with an aqueous-based fluid, and any combination thereof. Suitable water-in-oil emulsions, also known as invert emulsions, may have an oil-to-water ratio from a lower limit of greater than about 50:50, 55:45, 60:40, 65:35, 70:30, 75:25, or 80:20 to an upper limit of less than about 100:0, 95:5, 90:10, 85:15, 80:20, 75:25, 70:30, or 65:35 by volume in the base fluid, where the amount may range from any lower limit to any upper limit and encompass any subset therebetween.
In some instances, detonation of the encapsulated explosives may be triggered mechanically. For example, the encapsulated explosives may be crushed between the downhole cutting tool and the subterranean formation and the physical act of crushing or grinding the encapsulated explosives serves to trigger their respective detonations. In another example, a sonicator (refer to FIG. 2B) arranged within the downhole cutting tool may be used such that cavitation generated by the sonicator detonates the encapsulated explosives.
In some instances, detonation of the encapsulated explosives may be triggered thermally. For example, the composition encapsulating the explosive may be exposed to electromagnetic radiation having a frequency of about 10⁶Hz to about 10¹⁷Hz, thereby causing the encapsulating composition to heat and trigger detonation of the explosive. By way of nonlimiting example, encapsulated explosives that include functionalized fullerenes (e.g., dendrofullerenes) or functionalized nanotubes for encasement (e.g., via a liposome, micelle, or polymeric coating) may be heated with exposure to infrared light or microwave radiation.
In another example that involves both thermal and mechanical detonation, a mixture of first and second encapsulated explosives may be used where the first encapsulated explosive is at a lower concentration, has a higher sensitivity to detonation, and has a higher explosive intensity than the second encapsulated explosive. In such embodiments, detonation of the first encapsulated explosive may be configured to detonate the second encapsulated explosive.
In some instances, detonation of the encapsulated explosives may be triggered chemically. For example, the composition encapsulating each of the components of a binary explosive may be compromised such that the two components may contact and detonate. Compromising the composition encapsulating the components may be achieved mechanically and/or thermally as described herein relative to detonation. In other instances, compromising the composition encapsulating the components may be chemical triggering by changing the pH and/or salinity of the drilling fluid. For example, liposomes and micelles that include ionic surfactants and/or polymers may be compromised upon pH and salinity changes.
Triggering detonation of the encapsulated explosives may occur at any point along a drilling system. For example, referring now to FIGS. 2A and 2B, illustrated are top and cross-sectional views, respectively, of an exemplary impregnated drill bit 200. The drill bit 200 may be used for triggering detonation via cavitation. The drill bit 200 has cutting surfaces 202 for removing rock from the bottom of a borehole. Drilling fluid flows through the interior passage 204 (FIG. 2B) of the drill string 206 and into a cavity 208 defined within the drill bit 200 before exiting the drill bit 200 through various ports 210 defined in the head of the bit 200. As illustrated in FIG. 2B, a sonicator 212 may extend into the cavity 208 of the drill bit 200 and may be capable of producing cavitation in the drilling fluid passing through the cavity 208. The location of the sonicator 212 within cavity 208, the composition of the encapsulated explosive, and the flow rate of the drilling fluid may be manipulated such that triggering the encapsulated explosives occurs within the cavity 208, but detonation thereof occurs after the encapsulated explosives have exited the ports 210.
In some instances, the sonicator 212 may be replaced with a laser or other device that produces electromagnetic radiation of a desired frequency. Accordingly, the drill bit 200 may equally be useful for thermal triggering of the encapsulated explosive. One skilled in the art, with the benefit of this disclosure, should recognize the plurality of ways to implement these triggering devices in the impregnated drill bit 200 or any other downhole cutting tool.
Referring now to FIG. 3, illustrated is an exemplary reamer 314. As illustrated, the reamer 314 may include a body 316 coupled to a stem 318. The body 316 may include one or more blocks 320 and/or one or more legs 322 coupled thereto or otherwise formed thereon. In the illustrated embodiment of FIG. 3, the reamer 314 includes four blocks 320 and four legs 322 disposed radially around the body 316, for example, in alternating fashion. However, the reamer 314 alternatively may include any number of blocks 320 and legs 322, in any combination, as required by a particular application. The blocks 320 may be, for example, stabilizers or gauge pads, or they may include cutting elements, such as PDC cutters. In some embodiments, the blocks 320 may include hardware 324 capable of triggering detonation of the encapsulated explosive (e.g., sonicators, lasers, or other devices that produce electromagnetic radiation a desired frequency).
Each leg 322 may include a head 326, which may include bearings, seals, or other components for supporting cutting elements, such as a roller cone 328, for reaming a wellbore. The stem 318 may include one or more fluid orifices 330 and/or a downhole connector 332 for coupling the reamer 314 to other components in a drilling or reaming system, such as a pilot bit 334 or other drilling equipment. The connector 332 may include threads, holes, pins, profiles, or like components, as required by a particular application. In the exemplary embodiment of FIG. 3, the pilot bit 334 is depicted as a hybrid bit, but it is to be understood that the pilot bit 334 may be any bit required by a particular application, such as a PDC bit, an impregnated bit, or a roller cone bit. In some instances, the pilot bit 334 may be include hardware capable of triggering the encapsulated explosives, such as the hardware described above relative to FIGS. 2A and 2B (e.g., sonicators, lasers, etc.).
One of ordinary skill in the art, with the benefit of this disclosure, would recognize the plurality of other configurations for including hardware capable of triggering detonation. For example, the hardware may be between the reamer 314 and the pilot bit 334 and coupled to the connector 332 of FIG. 3. In another example, the hardware may be coupled to a stabilizer (not shown) that is coupled to a drill bit 200 (FIGS. 2A and 2B), a pilot bit 334, a reamer 314, or a connector 332, or other similar downhole cutting tool or portion thereof.
In some instances, the encapsulated explosives may be in the drilling fluid when the drilling fluid is introduced into a wellbore. In other instances, the encapsulated explosives may be added to the drilling fluid at a point along the drill string. For example, FIG. 4 illustrates a cross-section of a portion of a drill string 406 coupled to an impregnated drill bit 400 where the drill string 406 is configured to add encapsulated explosives to the drilling fluid circulating therethrough at one or more points along the drill string 406. The drill string 406 may include one or more reservoirs 436 (two shown) arranged upstream from the impregnated drill bit 400, which may alternatively be any other downhole cutting tool. The reservoirs 436 may contain a plurality of encapsulated explosives 438 and may be signaled to release the encapsulated explosives 438 into the drilling fluid via a communication line 440, or other suitable communication method (e.g., acoustic telemetry, electromagnetic telemetry, radio waves, electronic signaling, etc.). Upon receiving a predetermined signal, the reservoir 436 may be configured to release at least some of the encapsulated explosives 438 into the drilling fluid flowing through the drill string 406. The encapsulated explosives 438 may be triggered by any of the methods described herein.
In some instances, the drill string 406 coupled to the impregnated drill bit 400 illustrated in FIG. 4 may be useful in chemical triggering where the reservoir 436 contains the chemical trigger (e.g., acids, bases, salts, and the like) or one of the two encapsulated components of a binary explosive composition. As will be appreciated, using the reservoir(s) may advantageously mitigate the risk of premature explosion of the encapsulated explosives in the drill string upstream of the downhole cutting tool.
Referring again to FIG. 3, with continued reference to FIG. 4, portions of the hardware 324 arranged on the reamer 314 may be replaced with a reservoir similar to the reservoir 436 of FIG. 4. Again, using the reservoir 436 may advantageously allow further mitigation of the risk of premature explosion.
In some embodiments, the detonation of encapsulated explosives may be intermittent relative to the drilling operation. For example, the encapsulated explosives may be added to the drilling fluid intermittently (e.g., prior to introduction into the wellbore or from a reservoir). In another example, triggering detonation of the encapsulated explosives may be performed intermittently, wherein the encapsulated explosives are present in the drilling fluid when triggering is not being performed. In some instances, a hybrid of the two may be performed. Intermittent use and/or triggering of the encapsulated explosives may further mitigate risks associated with their use.
In some embodiments, while drilling a wellbore penetrating a subterranean formation, the encapsulated explosives may be implemented (e.g., included in the drilling fluid, triggered, or both) relative to select lithologies found within the subterranean formation, so as to complement drilling through the lithology. In some instances, detecting the lithology may be accomplished via one or more sensors arranged adjacent a downhole cutting tool (e.g., on a bottom hole assembly, etc.), a drill string, or the like. In another example, the torque, rate of penetration, wellbore pressure, and other parameters used for drilling may indicate that a particular lithology has been encountered where implementation of encapsulated explosives may be useful. In yet another example, seismic data and other formation data (e.g., core samples or drilling history of a wellbore into the same formation) may be utilized in identifying the select lithologies. In another example, a logging/measurement while drilling system may autonomously send signals or otherwise communicate to trigger the encapsulated explosive (or release the encapsulated explosives) based on the information about the subterranean formation determined from the logging/measurement activity of the drilling system. In some embodiments, combinations of the foregoing methods may be used for determining when to implement the encapsulated explosives.
Embodiments disclosed herein include:
A: a method that includes drilling a wellbore penetrating a subterranean formation with a downhole cutting tool; circulating a drilling fluid in the wellbore, wherein the drilling fluid comprises a base fluid and an encapsulated explosive having an average diameter of about 10 nm to about 20 microns; triggering detonation of the encapsulated explosive; and detonating the encapsulated explosive proximal to a portion of the subterranean formation adjacent the downhole cutting tool;
B: a method that includes drilling a wellbore penetrating a subterranean formation with a downhole cutting tool operably coupled to a drill string and a reservoir being coupled to at least one selected from the group consisting of the downhole cutting tool and the drill string, wherein the reservoir contains a plurality of encapsulated explosives; circulating a drilling fluid in the wellbore; releasing at least a portion of the encapsulated explosives from the reservoir and into the drilling fluid, the encapsulated explosives having an average diameter of about 10 nm to about 20 microns; triggering detonation of the encapsulated explosives in the drilling fluid; and detonating the encapsulated explosives proximal to a portion of the subterranean formation adjacent the downhole cutting tool; and
C: a method that includes drilling a wellbore penetrating a subterranean formation with a downhole cutting tool operably coupled to a drill string and a reservoir being coupled to at least one of the downhole cutting tool and the drill string, wherein the reservoir contains a plurality of first encapsulated components; circulating a drilling fluid in the wellbore, the drilling fluid comprising a base fluid and a plurality of second encapsulated components, wherein the first and second pluralities of encapsulated components form part of a binary explosive; releasing at least a portion of the first encapsulated components from the reservoir into the drilling fluid; triggering detonation of the binary explosive by comingling the first encapsulated components with the second encapsulated components; and detonating the binary explosive proximal to a portion of the subterranean formation adjacent the downhole cutting tool.
Each of embodiments A, B, and C may have one or more of the following additional elements, unless otherwise provided for, in any combination: Element 1: wherein triggering detonation of the encapsulated explosive comprises irradiating the encapsulated explosive with electromagnetic radiation having a frequency of about 10⁶Hz to about 10¹⁷Hz; Element 2: wherein triggering detonation of the encapsulated explosive comprises crushing the encapsulated explosive between the downhole cutting tool and the subterranean formation; Element 3: wherein triggering detonation of the encapsulated explosive comprises introducing cavitation into the drilling fluid; Element 4: wherein triggering detonation of the encapsulated explosive comprises contacting the encapsulated explosive with a chemical trigger; Element 5: wherein triggering detonation of the encapsulated explosive is intermittent; Element 6: triggering detonation of the encapsulated explosive occurs upstream of the drill bit in a drill string coupled to the downhole cutting tool; Element 7: wherein the encapsulated explosive comprises at least one selected from the group consisting of a liposome, a crosslinked liposome, a nanoliposome, a polymeric vesicle, a dendritic polymer, a coated nanoparticle, a coated microparticle, an impregnated nanoparticle, an impregnated microparticle, and any hybrid thereof; Element 8: wherein the encapsulated explosive comprises at least one selected from the group consisting of thermite, octogen, pentaerythritol tetranitrate, tetranitrotoluene, an explosive nitroamine, lead picrate, mercury fulminate, nitrogen triiodide, potassium perchlorate, ammonium perchlorate, and the like, and a combination thereof; Element 9: wherein the encapsulated explosive comprises a first encapsulated explosive and a second encapsulated explosive, and wherein the first encapsulated explosive has a higher sensitivity to detonation than the second encapsulated explosive; Element 10: wherein the encapsulated explosive is a binary explosive comprising two components that are each encapsulated individually; Element 11:
wherein the encapsulated explosive is a binary explosive comprising two components that are each encapsulated individually, and wherein the two components comprise at least one pair selected from the group consisting ammonium nitrate/fuel oil, ammonium nitrate/nitromethane, ammonium nitrate/aluminum, and nitroethane/physical sensitizer; and Element 12: wherein the encapsulated explosive has an average diameter of about 10 nm to about 500 nm.
By way of non-limiting example, exemplary combinations applicable to A, B, C include: at least two of Elements 1-4; Element 5 in combination with at least one of Elements 1-4; Element 6 in combination with at least one of Elements 1-4; Element 5 in combination with Element 6; Element 5 in combination with Element 6 and at least one of Elements 1-4; at least two of Elements 7-11; Element 5 in combination with at least one of Elements 7-11; Element 6 in combination with at least one of Elements 7-11; Element 5 in combination with Element 6 and at least one of Elements 7-11; Element 12 in combination with one of the foregoing combinations; Element 5 in combination with Element 12; and Element 6 in combination with Element 12.
One or more illustrative embodiments incorporating the principles of the disclosure described herein are presented below. Not all features of an actual implementation are described or shown in this application for the sake of clarity. It is understood that in the development of an actual embodiment incorporating the present disclosure, numerous implementation-specific decisions must be made to achieve the developer's goals, such as compliance with system-related, business-related, government-related and other constraints, which vary by implementation and from time to time. While a developer's efforts might be complex and time-consuming, such efforts would be, nevertheless, a routine undertaking for those of ordinary skill the art having benefit of this disclosure.
It should be noted that when the term “about” is provided herein at the beginning of a numerical list, the term modifies each number of the numerical list. In some numerical listings of ranges, some lower limits listed may be greater than some upper limits listed. One skilled in the art will recognize that the selected subset will require the selection of an upper limit in excess of the selected lower limit. Unless otherwise indicated, all numbers expressing quantities of ingredients, properties such as molecular weight, reaction conditions, and so forth used in the present specification and associated claims are to be understood as being modified in all instances by the term “about.” Accordingly, unless indicated to the contrary, the numerical parameters set forth in the following specification and attached claims are approximations that may vary depending upon the desired properties sought to be obtained by the exemplary embodiments described herein. At the very least, and not as an attempt to limit the application of the doctrine of equivalents to the scope of the claim, each numerical parameter should at least be construed in light of the number of reported significant digits and by applying ordinary rounding techniques.
Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present disclosure. The disclosure illustratively described herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

Claims

What is claimed is:

1. A method comprising:

drilling a wellbore penetrating a subterranean formation with a downhole cutting tool;

circulating a drilling fluid in the wellbore, wherein the drilling fluid comprises a base fluid and an encapsulated explosive having an average diameter of about 10 nm to about 20 microns;

triggering detonation of the encapsulated explosive; and

detonating the encapsulated explosive proximal to a portion of the subterranean formation adjacent the downhole cutting tool.

2. The method of claim 1, wherein triggering detonation of the encapsulated explosive comprises irradiating the encapsulated explosive with electromagnetic radiation having a frequency of about 10⁶Hz to about 10¹⁷Hz.

3. The method of claim 1, wherein triggering detonation of the encapsulated explosive comprises crushing the encapsulated explosive between the downhole cutting tool and the subterranean formation.

4. The method of claim 1, wherein triggering detonation of the encapsulated explosive comprises introducing cavitation into the drilling fluid.

5. The method of claim 1, wherein triggering detonation of the encapsulated explosive is intermittent.

6. The method of claim 1, triggering detonation of the encapsulated explosive occurs upstream of the drill bit in a drill string coupled to the downhole cutting tool.

7. The method of claim 1, wherein the encapsulated explosive comprises at least one selected from the group consisting of a liposome, a crosslinked liposome, a nanoliposome, a polymeric vesicle, a dendritic polymer, a coated nanoparticle, a coated microparticle, an impregnated nanoparticle, an impregnated microparticle, and any hybrid thereof.

8. The method of claim 1, wherein the encapsulated explosive comprises at least one selected from the group consisting of thermite, octogen, pentaerythritol tetranitrate, tetranitrotoluene, an explosive nitroamine, lead picrate, mercury fulminate, nitrogen triiodide, potassium perchlorate, ammonium perchlorate, and the like, and a combination thereof.

9. The method of claim 1, wherein the encapsulated explosive comprises a first encapsulated explosive and a second encapsulated explosive, and wherein the first encapsulated explosive has a higher sensitivity to detonation than the second encapsulated explosive.

10. The method of claim 1, wherein the encapsulated explosive is a binary explosive comprising two components that are each encapsulated individually.

11. The method of claim 10, wherein the two components comprise at least one pair selected from the group consisting ammonium nitrate/fuel oil, ammonium nitrate/nitromethane, ammonium nitrate/aluminum, and nitroethane/physical sensitizer.

12. The method of claim 1, wherein the encapsulated explosive has an average diameter of about 10 nm to about 500 nm.

13. A method comprising:

drilling a wellbore penetrating a subterranean formation with a downhole cutting tool operably coupled to a drill string and a reservoir being coupled to at least one of the downhole cutting tool and the drill string, wherein the reservoir contains a plurality of encapsulated explosives;

circulating a drilling fluid in the wellbore;

releasing at least a portion of the encapsulated explosives from the reservoir and into the drilling fluid, the encapsulated explosives having an average diameter of about 10 nm to about 20 microns;

triggering detonation of the encapsulated explosives in the drilling fluid; and

detonating the encapsulated explosives proximal to a portion of the subterranean formation adjacent the downhole cutting tool.

14. The method of claim 13, wherein releasing the at least a portion of the encapsulated explosives from the reservoir is intermittent.

15. The method of claim 13, wherein triggering detonation of the encapsulated explosive comprises irradiating the encapsulated explosive with electromagnetic radiation having a frequency of about 10⁶Hz to about 10¹⁷Hz.

16. The method of claim 13, wherein triggering detonation of the encapsulated explosive comprises crushing the encapsulated explosive between the downhole cutting tool and the subterranean formation.

17. The method of claim 13, wherein triggering detonation of the encapsulated explosive comprises exposing the encapsulated explosive to cavitation.

18. The method of claim 13, wherein triggering detonation of the encapsulated explosive comprises contacting the encapsulated explosive with a chemical trigger.

19. A method comprising:

drilling a wellbore penetrating a subterranean formation with a downhole cutting tool operably coupled to a drill string and a reservoir being coupled to at least one of the downhole cutting tool and the drill string, wherein the reservoir contains a plurality of first encapsulated components;

circulating a drilling fluid in the wellbore, the drilling fluid comprising a base fluid and a plurality of second encapsulated components, wherein the first and second pluralities of encapsulated components form part of a binary explosive;

releasing at least a portion of the first encapsulated components from the reservoir into the drilling fluid;

triggering detonation of the binary explosive by comingling the first encapsulated components with the second encapsulated components; and

detonating the binary explosive proximal to a portion of the subterranean formation adjacent the downhole cutting tool.

20. The method of claim 19, wherein releasing the at least a portion of the first encapsulated components from the reservoir is intermittent.