Classifications

• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/02—Well-drilling compositions
  • C09K8/03—Specific additives for general use in well-drilling compositions
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
  • E21B21/01—Arrangements for handling drilling fluids or cuttings outside the borehole, e.g. mud boxes
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B7/00—Special methods or apparatus for drilling
  • E21B7/007—Drilling by use of explosives
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F42—AMMUNITION; BLASTING
  • F42D—BLASTING
  • F42D1/00—Blasting methods or apparatus, e.g. loading or tamping
  • F42D1/08—Tamping methods; Methods for loading boreholes with explosives; Apparatus therefor
  • F42D1/10—Feeding explosives in granular or slurry form; Feeding explosives by pneumatic or hydraulic pressure

Definitions

• 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.
• 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.
• 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.
• 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.
• an increased rate of penetration may be achieved with less torque and energy consumption and less downhole cutting tool wear.
• well operators may benefit from decreases in the cost and time of drilling operations.
• downhole cutting tool refers to downhole tools capable of drilling at least a portion of a wellbore penetrating a subterranean formation.
• 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.
• PDC polycrystalline diamond compact
• FIG. 1 illustrates an exemplary system that may implement the principles of the present disclosure, according to one or more embodiments.
• 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.
• drilling fluid shown as flow arrows A
• WOB weight-on-bit
• the cutting elements apply a compressive stress that exceeds the yield stress of the formation, thereby grinding through the formation.
• 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.
• encapsulated explosive refers to an explosive composition substantially encased by another composition.
• 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.
• 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).
• binary explosive compositions may include, but are not limited to, ammonium nitrate/fuel oil, ammonium nitrate/nitromethane, ammonium nitrate/aluminum, and nitroethane/physical sensitizer.
• 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.
• 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.
• 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.
• glycerins e.g., 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.
• salts e.g., sodium chloride, calcium chloride, calcium bromide, zinc bromide, potassium carbonate, sodium formate, potassium formate, cesium formate, sodium acetate, potassium acetate
• 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.
• detonation of the encapsulated explosives may be triggered mechanically.
• 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.
• 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.
• detonation of the encapsulated explosives may be triggered thermally.
• the composition encapsulating the explosive may be exposed to electromagnetic radiation having a frequency of about 10 6 Hz to about 10 17 Hz, thereby causing the encapsulating composition to heat and trigger detonation of the explosive.
• encapsulated explosives that include functionalized fullerenes (e.g., dendrofullerenes) or functionalized nanotubes for encasement may be heated with exposure to infrared light or microwave radiation.
• 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.
• detonation of the first encapsulated explosive may be configured to detonate the second encapsulated explosive.
• detonation of the encapsulated explosives may be triggered chemically.
• 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.
• compromising the composition encapsulating the components may be chemical triggering by changing the pH and/or salinity of the drilling fluid.
• 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.
• 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.
• 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.
• 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.
• 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.
• the reamer 314 includes four blocks 320 and four legs 322 disposed radially around the body 316, for example, in alternating fashion.
• 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.
• 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.
• 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.
• 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.).
• the hardware may be between the reamer 314 and the pilot bit 334 and coupled to the connector 332 of FIG. 3.
• 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.
• 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.
• 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.).
• a communication line 440 or other suitable communication method (e.g., acoustic telemetry, electromagnetic telemetry, radio waves, electronic signaling, etc.).
• 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.
• 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.
• the chemical trigger e.g., acids, bases, salts, and the like
• 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.
• 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.
• the detonation of encapsulated explosives may be intermittent relative to the drilling operation.
• the encapsulated explosives may be added to the drilling fluid intermittently (e.g., prior to introduction into the wellbore or from a reservoir).
• 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.
• 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.
• 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.
• 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.
• 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.
• seismic data and other formation data may be utilized in identifying the select lithologies.
• 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.
• 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 10 6 Hz to about 10 17 Hz;
• 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;
• 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.
• 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.

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• Engineering & Computer Science (AREA)
• Life Sciences & Earth Sciences (AREA)
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• Mining & Mineral Resources (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Geochemistry & Mineralogy (AREA)
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• Environmental & Geological Engineering (AREA)
• Physics & Mathematics (AREA)
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• Materials Engineering (AREA)
• Organic Chemistry (AREA)
• General Engineering & Computer Science (AREA)
• Mechanical Engineering (AREA)
• Earth Drilling (AREA)
• Perforating, Stamping-Out Or Severing By Means Other Than Cutting (AREA)
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• 2013
  • 2013-08-27 CA CA2917846A patent/CA2917846C/en not_active Expired - Fee Related
  • 2013-08-27 GB GB1600217.2A patent/GB2532884A/en active Pending
  • 2013-08-27 DE DE112013007387.0T patent/DE112013007387T5/de not_active Withdrawn
  • 2013-08-27 WO PCT/US2013/056839 patent/WO2015030732A1/en active Application Filing
  • 2013-08-27 CN CN201380078183.2A patent/CN105378216A/zh active Pending
  • 2013-08-27 US US14/377,385 patent/US20160032654A1/en not_active Abandoned
• 2014
  • 2014-06-19 AR ARP140102340A patent/AR096676A1/es unknown

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