CN117413114A

CN117413114A - Projectile drilling system

Info

Publication number: CN117413114A
Application number: CN202280039203.4A
Authority: CN
Inventors: M·C·拉塞尔; L·D·安德伍德; L·范斯通; P·贝利; D·E·伯纳德; T·切特歇尔; K·J·德基; K·纽伯格; A·J·阿贝塔
Original assignee: Hypersciences Inc
Current assignee: Hypersciences Inc
Priority date: 2021-03-30
Filing date: 2022-03-29
Publication date: 2024-01-16

Abstract

The projectile weakens the geological material in the wellbore by accelerating the material into contact with the material. A drill bit is then used to drill through the weakened material. To accelerate the projectile, an end cap is placed in the conduit using a gas source. The end cap isolates the conduit from the external environment. The projectile is then positioned in the conduit over the end cap. A movable member within the conduit is sequentially operated to enable a single end cap and cartridge to be moved into the conduit. Gas from the conduit is evacuated into the annulus between the conduit and the surrounding conduit and propellant material is provided into the conduit. The propellant material applies a force to the projectile to accelerate the projectile into contact with the geological material. Fluid is circulated along a second annulus external to the surrounding conduit to contact the drill bit and remove debris.

Description

Projectile drilling system

Priority

The present application claims priority from U.S. patent application Ser. No. 17/656,133 filed on 3/23 at 2022. U.S. patent application Ser. No. 17/656,133 is incorporated by reference in its entirety.

The present application also claims priority from U.S. provisional patent application Ser. No. 63/168,133 filed 3/30/2021. U.S. patent application Ser. No. 63/168,133 is incorporated herein by reference in its entirety.

Incorporated by reference

The following U.S. patents and patent applications are incorporated by reference in their entirety:

U.S. patent application Ser. No. 13/841,236, entitled "Ram Accelerator System," filed on 3, 3 and 15, now published as U.S. patent 9,500,419.

U.S. patent application 14/708,932 entitled "Ram Accelerator System with Endcap" filed on 5.11.2015, now published as U.S. patent 9,458,670.

U.S. patent application 14/919,657, entitled "Ram Accelerator System with Rail Tube", filed on 10 months 21 in 2015, is now published as U.S. patent 9,988,844.

U.S. patent application 15/135,452, entitled "Ram Accelerator System with Baffles", filed 4/21/2016, is now published as U.S. patent 10,697,242.

U.S. patent application Ser. No. 15/340,753, entitled "Projectile Drilling System," filed 11/1/2016, now published as U.S. patent 10,557,308.

U.S. patent application 15/698,549, entitled "Augmented Drilling System," filed on 7, 9, and 7, now published as U.S. patent 10,590,707.

U.S. patent application 15/348,796 entitled "System for Generating a Hole Using Projectiles" filed 11/10 a/2016 is now published as U.S. patent 10,329,842.

U.S. patent application 15/871,824, entitled "System for Acoustic Navigation of Boreholes," filed 1/15/2018, is now published as U.S. patent 10,914,168.

Technical Field

Conventional drilling, excavation, and tunnel excavation methods use drill bits or other drilling tools, or in some cases blasting operations, to penetrate rock or other types of geologic materials. Drilling or excavation to form a hole may be used in a variety of situations, such as extracting hydrocarbons, water, or geothermal energy from beneath the earth's surface, forming tunnels or shafts for mining operations, and the like. The rate and other characteristics of formation of the wellbore may be affected by the characteristics of the geologic material, such as the presence of hard rock.

Drawings

The specific embodiments are described with reference to the drawings.

FIG. 1 is a diagram depicting an implementation of a system that may be used to provide an end cap and a projectile into a wellbore for use in combination with a drill bit to extend the wellbore through geological materials.

FIG. 2 is a diagram depicting a side cross-sectional view of a portion of a swivel assembly and a conduit for providing an end cap and a projectile into a wellbore.

FIG. 3 is a series of diagrams depicting implementations of a conduit assembly that may be used to provide end caps, projectiles, and other materials into a wellbore.

FIG. 4 is a diagram depicting an implementation of a Bottom Hole Assembly (BHA) and an associated conduit string.

FIG. 5 is a diagram depicting an implementation of a gas diverter, a pre-load tube, a metering tube, and a gas gate within a Bottom Hole Assembly (BHA).

FIG. 6A is a diagram depicting an isometric exploded view of an implementation of a metering tube within a Bottom Hole Assembly (BHA).

FIG. 6B is a series of diagrams depicting side and cross-sectional views of the metering tube of FIG. 6A in upper and lower actuated positions.

Fig. 7 is a diagram depicting an isometric cross-sectional view of one implementation of a configuration of a valve within a breech tube.

FIG. 8 is a flow chart depicting an implementation of a method for providing end caps, projectiles, and propellant material into a conduit string and extending a wellbore using a projectile and drill bit.

Fig. 9A is a diagram depicting an exploded partial cross-sectional view of an implementation of a pump that may be used to remove gas or fluid from a breech or launch tube.

Fig. 9B is a series of diagrams depicting side cross-sectional and assembly views of the pump of fig. 9A.

FIG. 10 is a diagram depicting a diagrammatic cross-sectional view of a conduit string including three conduits and associated annulus that may be used to provide gas, end caps, projectiles, and fluids into a wellbore and circulate gas, fluids, and debris toward the surface of the wellbore.

FIG. 11A is a diagram depicting a side cross-sectional view of an implementation of an end cap retention mechanism for retaining an end cap within a catheter.

Fig. 11B is a series of diagrams depicting an exploded view and a diagrammatic side cross-sectional view of the end cap retention mechanism of fig. 11A.

Fig. 11C is a series of diagrams depicting perspective and cross-sectional views of an implementation of an end cap.

Fig. 12A-12C are a series of diagrams depicting implementations of projectiles that may be used to interact with geological materials.

FIG. 13 is a diagram depicting an implementation of a system that may include a source of propellant material that may be located downhole within the system.

Although implementations are described by way of example in this disclosure, those skilled in the art will recognize that the implementations are not limited to the examples or figures described. It should be understood that the drawings and detailed description thereto are not intended to limit the implementation to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims. Headings are used in this disclosure for organizational purposes only and are not meant to be used to limit the scope of the description or the claims. As used throughout this application, the word "may" is used in a permissive sense (i.e., meaning having the potential to), rather than the mandatory sense (i.e., meaning must). Similarly, the words "include", "including" and "comprising" mean "including but not limited to".

Detailed Description

Drilling into the earth, such as by forming a wellbore, shaft, tunnel, or other opening, may be performed using a variety of tools and methods, such as milling, breaking, or scraping the geologic. For example, a drill bit may be used to form a wellbore through a geologic material to form hydrocarbon wells, water wells, geothermal wells, and the like. Drilling operations progress slowly as hard rock and other high hardness materials are drilled through, which may result in some inefficiencies or uneconomical operations. In addition, drilling operations may subject drill bits and other equipment to severe wear, mechanical forces, high temperatures, high pressures, etc., which may require frequent maintenance or replacement of various components, further increasing costs and slowing down operations.

Described in this disclosure are systems and methods for forming a wellbore or other type of opening through a geological material, wherein a projectile is accelerated to contact rock or other geological material to remove, destroy, or weaken the material via impact. In some implementations, the projectile may be propelled through one or more tubes or other conduits by gases that may be generated using a combustion process. The accelerated projectile may reach high velocities, which may enable the projectile to fracture or otherwise weaken or degrade the impacted geologic material. In some implementations, the ram accelerator assembly may utilize a ram effect to accelerate the projectile using pressurized gas, the ram effect being caused by interactions between external features of the projectile and internal features of a tube or other conduit of the ram accelerator assembly. The broken or weakened geological material may then be contacted by the drill bit, which may more easily penetrate the weakened material, enabling less time and energy to be used to form a portion of the wellbore than conventional methods, and causing less wear to the drill bit and other components of the system.

A pressure barrier, such as an end cap, may be conveyed along a drill string or other type of conduit and positioned at or near the terminal end of the conduit. For example, a gas source such as air may be used to deliver the end caps. When positioned within the conduit, the end cap may isolate the interior of the conduit from the external environment. For example, the arrangement of end caps may prevent wellbore fluid from entering the end of the conduit, and may enable the conduit to be maintained at a pressure different from the pressure of the environment external to the conduit. The projectile may also be delivered into the conduit, such as by circulating air or another gas along the conduit. The gas may then be removed from the conduit, such as by venting the gas from the conduit into an annulus outside the conduit, where the gas may flow to the surface. In other implementations, a pump (such as an annular pump mounted to the outside of the conduit) may be used to remove gas from the conduit. In some implementations, a fluid other than air, gas, or a mixture of gases (such as water) may be used to transport the end cap and projectile into the conduit, and the fluid may be removed into an adjacent annulus or removed using a pump.

In some implementations, the propellant material may be provided into the conduit using a fuel line or other type of tube or separate conduit extending through the annulus adjacent the conduit. The propellant material may exert a force on the projectile, such as when ignited or burned, thereby accelerating the projectile through the conduit. As the projectile exits the catheter and contacts the geological material, the geological material may be weakened, broken or otherwise degraded. For example, interactions between the projectile and the geologic material may form cracks, thereby weakening the geologic material. In some cases, water or other wellbore fluids may fill the formed fractures, thereby exerting a force on the geologic material, which further weakens or ruptures the geologic material. In some implementations, a drill bit engaged with the end of the catheter may be used to drill through weakened or degraded material. Water, drilling mud, or other types of fluids may be conveyed along the separate annulus to contact the drill bit and to divert debris formed by the interaction between the projectile or drill bit and the geologic material, which may be used to convey the debris to the surface. In some implementations, air or other gas delivered through the conduit in addition to or instead of water or other fluid may displace the cuttings. However, with water flowing, the cuttings may become wet, heavier, clumped, etc., and water, drilling fluid, or other fluids may be used in addition to or instead of air to divert the cuttings from the wellbore.

In some implementations, multiple end caps and projectiles may be conveyed along a conduit and moved individually into a launch tube, allowing the projectiles to be repeatedly accelerated into the geologic material during a drilling operation. The resulting system may allow for faster formation of a wellbore or other type of opening in a geologic material, as compared to existing tools and methods, thereby allowing for efficient and economical drilling of formations having hard rock and other materials of higher hardness.

Accordingly, the systems and methods described herein may enable the use, at least in part, of the impact of a projectile to form a wellbore or other type of opening within a geologic material. End caps, projectiles, propellant materials, air or other gases, and water or other fluids (such as drilling fluids) may be provided from a fluid source through a drill string or other conduit to a Bottom Hole Assembly (BHA), which may be submerged in the water or drilling fluid in some cases. The BHA may include features that enable multiple end caps and projectiles to be provided into the system while providing the following advantages: protecting the received end cap and projectile from damage, controlling the individual placement of the end cap and projectile, and protecting the end cap and projectile from forces such as high pressure shock waves that may occur when the projectile is accelerated or the propellant material burns. The described systems and methods may also enable the conduit to be at least partially evacuated of air such that projectiles and propellant materials disposed in the conduit may be effectively accelerated to contact geological materials.

FIG. 1 is a diagram depicting one implementation of a system 100, the system 100 being operable to provide end caps and projectiles into a wellbore for use in conjunction with a drill bit 102 to extend the wellbore through a geologic material. Drilling operations for forming wellbores may utilize mechanisms for lifting various components, such as cable-based winches, hydraulic cylinders, or the like. The drilling operation may also use a rotary drive mechanism, such as a mechanical or hydraulic drive system, that delivers rotation to a drill string or other type of conduit 104 within the wellbore. Additionally, the drilling operation may include the use of swivel 106, which may include an assembly for providing fluid or other components into conduit 104 and removing fluid or other components from conduit 104. For example, the swivel 106 may include a series of inlets and outlets for providing fluid and other components into the non-rotating body and delivering fluid or other components into the rotating body. In some cases, the swivel 106 and the rotary drive may be integrated into a single unit, such as a top drive, a powered swivel, or a top rotary drive. These components, in combination, may deliver fluid into a drill string or other type of conduit 104 while also transmitting torque to the conduit 104 and raising or lowering the conduit 104.

The system 100 shown in fig. 1 may be used to accelerate projectiles into a geologic material, which may weaken, fracture, or otherwise degrade the geologic material, and then contact the weakened geologic material with the drill bit 102 to extend the wellbore. The swivel 106 assembly may include a plurality of inlets and outlets to provide fluid and other materials into the string of conduits 104 and to receive fluid and other materials from the string of conduits 104. For example, a container 108 containing one or more end caps or projectiles may be engaged with swivel 106 such that the end caps and projectiles from container 108 may enter conduit 104 through an inlet. The gas inlet 110 may be used to provide air or another gas into the conduit 104, which may be used to transport the end cap and the projectile through the conduit 104, and in some cases may transfer cuttings or other debris formed by interactions between the geological material and the projectile or drill bit 102. Propellant inlets 112 may provide propellant material into conduit 104 that may be used to provide a force to the projectile, such as when ignited or otherwise burned or actuated, to accelerate the projectile out of conduit 104 and into contact with geologic material. For example, air or another gas or gas mixture including oxygen may be provided into the gas inlet and through conduit 104 to bottom hole assembly BHA 114. Air or other gas may transport the end cap and projectile from the container 108 to the BHA 114. For example, the end cap may seal a portion of the conduit 104 from the environment outside the conduit 104, which may enable an at least partially evacuated state by removing at least a portion of the gas from the conduit 104. At least a portion of the air or other gas may be vented from the portion of the conduit 104 within the BHA 114, but may retain sufficient air or provide sufficient air into the BHA 114 to enable ignition and combustion of the propellant material provided using the propellant inlet 112.

After accelerating the projectile into the geologic material, the drill bit 102 may contact the geologic material, thereby extending the wellbore. The fluid inlet 116 may be used to provide water, drilling mud, or other fluids into the conduit 104. The fluid may contact the drill bit 102 to lubricate or cool the drill bit 102, and may also transfer debris formed by interactions between the projectile or drill bit 102 and the geological material. For example, debris carried out of the wellbore by the fluid flow may pass through a flow diverter 118, where the debris may be conveyed to a debris outlet 120, which may include various screens, filters, tunnels, etc. for collecting, separating, treating, or transporting the debris. In some implementations, air or another gas provided through the gas inlet 110 may be used in addition to or in lieu of the fluid to remove debris from the wellbore.

For example, swivel 106 may be connected to a drill string or other type of conduit 104. As shown in fig. 1, in some implementations, the conduits 104 may include an inner first conduit 104 (1) and an outer second conduit 104 (2) positioned about the inner first conduit 104 (1) to define a first annulus 122 (1) between the two conduits 104. The second annulus 122 (2) may be defined between the exterior of the second conduit 104 (2) and the wellbore wall, or in some implementations, the second annulus may be defined between the exterior of the second conduit 104 (2) and a third conduit 104 positioned around the second conduit 104 (2). For example, the conduit 104 may include a drill string or other type of tubular string having two or more drill rods, each having at least an inner first conduit 104 (1) and an outer second conduit 104 (2). The second conduit 104 (2) may have a threaded connection capable of transmitting torque and sealing against fluid pressure. The first conduit 104 (1) may be mounted within the second conduit 104 (2) by a finned centralizer that centers the first conduit 104 (1) within the second conduit 104 (2). The first conduit 104 (1) may have a socket-type connection that may be sealed to prevent communication between the fluid within the inner conduit 104 (1) and the fluid in the first annulus 122 (1). As such, the inner first conduit 104 (1) may deliver the end cap, the projectile, and air or another gas to the BHA 114 through the conduit interior 126. Water or drilling fluid may be provided from a fluid source into the conduit 104 through the first annulus 122 (1) and debris and return fluid may flow to the surface through the second annulus 122 (2), or in other implementations, water or other fluid may be provided into the second annulus 122 (2) and returned through the first annulus 122 (1). In some implementations, a separate conduit 104 (such as a fuel line) may be placed in the first annulus 122 (1) or the second annulus 122 (2), and the conduit may transport the propellant to the BHA 114.

BHA 114 may house various components and subassemblies that may be used to perform various functions related to: accelerating the projectile; sorting the projectiles and end caps; selectively introducing a projectile and an end cap into a selected portion of the conduit 104; venting gas or fluid from the portion of conduit 104; propellant material and air or another gas are metered and provided into a portion of conduit 104; igniting a mixture of propellant material and air to provide force to the projectile, and so on. For example, a portion of the conduit 104 within the BHA 114 may include a breech pipe and a launch tube, which may be aligned with an opening extending through the drill bit 102, such that the projectile is able to strike and destroy or degrade geological material located in front of the drill bit 102. The drill bit 102 attached to the distal end of the BHA 114 may then be used to provide a mechanical cutting action to remove rock or other material near the perimeter of the wellbore, agitate loose rock cuttings and other debris to facilitate removal of the debris using a fluid stream, and so forth.

In some implementations, the end cap and the projectile may be made of frangible materials that are broken upon impact, such that debris generated by the broken end cap and projectile may be transferred from the wellbore by the circulating fluid. For example, the end cap and projectile housing may be made of polycarbonate plastic or other high strength plastic materials. In some implementations, the projectile may include a compact material (such as granite) or a composite of a high density material (such as barite) or metal particles (such as hematite or iron crayon). In other cases, the projectile may comprise metal powders bonded by cements or organic or inorganic binders or by sintering processes.

FIG. 2 is a diagram 200 depicting a side cross-sectional view of a portion of a swivel 106 assembly and a string of conduits 104 for providing an end cap and a projectile into a wellbore. Swivel 106 may include a non-rotating body with an inlet channel for providing end cap 202 and projectile 204 into the string of conduit 104. The end cap 202 and the projectile 204 may be arranged in the container 108 in an alternating fashion such that the first end cap 202 is provided into the conduit 104 prior to the first projectile 204. A second end cap 202 may be provided after the first projectile 204, and a second projectile 204 may be provided after the second end cap 202, and so on. Any number of end caps 202 and projectiles 204 may be provided into the conduit 104 in an alternating fashion such that the end caps 202 can be positioned to isolate the conduit interior 126 from the environment outside the conduit 104, after which the projectiles 204 are accelerated through the conduit 104 to contact the geological material. Although fig. 2 depicts the container 108 as having a magazine in a horizontal configuration, in other implementations, the end cap 202 and the projectile 204 may be stored in the container 108 having a vertical orientation. For example, a vertical stack of end caps 202 and projectiles 204 arranged in an alternating fashion may be provided into the conduit 104 (1) in close temporal proximity to each other. In other implementations, the container 108 may be placed on the ground or other surface, and the end cap 202 and projectile 204 may be delivered to the conduit 104 (1) using a tube, hose, or other type of conduit 104 that connects the container 108 to the conduit 104 (1). In other cases, the end cap 202 and projectile 204 may be fed into the air lock 206 using a conveyor system.

The inlet for the projectile 204 and the end cap 202, and the one or more gas inlets 110, may be connected to the conduit interior 126 of the interior first conduit 104 (1). The first conduit 104 (1) may be pressurized during drilling operations using air or another gas. Accordingly, the first conduit 104 (1) may include a damper 206 that includes one or more valves 208 to prevent pressurized gas from escaping the conduit 104 (1). As shown in fig. 2, the damper 206 may include an upstream first valve 208 (1) and a downstream second valve 208 (2) on opposite sides of the damper chamber. The first gas inlet 110 (1) may be connected to a damper chamber between the valves 208 and may be controlled using an air control valve (not shown). In operation, the end cap 202 or projectile 204 may enter the chamber of the air lock 206 when the first valve 208 (1) is open and the second valve 208 (2) is closed. The first valve 208 (1) is then closed and air is provided into the damper 206 using the gas inlet 110 (1) to increase the air pressure within the damper 206. The second valve 208 (2) is then opened to allow the end cap 202 or projectile 204 to enter the conduit 104 (1) from the air lock 206. The second valve 208 (2) may then be closed so that the swivel 106 assembly can provide a subsequent end cap 202 or projectile 204 into the air lock 206.

The container 108 and damper 206 may be connected to the housing of the swivel 106. The swivel 106 may be rotationally fixed relative to one or more components of the system 100, but capable of traveling in the axial direction of the string of conduits 104. The swivel 106 housing and conduit 104 (1) may receive the end cap 202, projectile 204, and air or other gas from the air lock 206. As described with respect to fig. 1, the swivel 106 may include a gas inlet 110 (2) for providing air or another gas into the inner first conduit 104 (1), a propellant inlet 112 for providing a propellant material into the annulus 122 (1) between the first conduit 104 (1) and the second conduit 104 (2), and a fluid inlet 116 for providing water or drilling fluid into the second annulus 122 (2) between the second conduit 104 (2) and the third conduit 104 (3). Although fig. 2 depicts the propellant inlet 112 providing propellant material into the annulus 122 (1), in other implementations the propellant inlet 112 may provide propellant material into a fuel line or other type of conduit 104 positioned within the annulus 122 (1). The outer third conduit 104 (3) may be supported on bearings in the housing of the swivel 106, which may allow the conduit 104 string to rotate. For example, the outer third conduit 104 (3) may be rotatable relative to the swivel 106, and the first conduit 104 (1), the second conduit 104 (2), and the third conduit 104 (3) may be connected such that the conduits 104 rotate simultaneously. Continuing with the example, the third conduit 104 (3) may be connected to a rotational drive 210, such as a chuck mechanism, that may clamp the outer surface of the third conduit 104 (3) and apply a rotational force thereto, thereby rotating the string of conduits 104 including the BHA 114 and the drill bit 102. An exemplary rotary drive 210 may include a DR900 manufactured by DR fabrics of Quebec, canada. As shown in fig. 2, the third conduit 104 (3) may pass through the center of a chuck mechanism that may clamp the third conduit 104 (3). In other implementations, the third conduit 104 (3) may be connected to the rotary drive 210 using a threaded connection or other type of engagement.

Although fig. 2 depicts swivel 106, inlet, and rotary drive 210 as separate components attached to each other, in other implementations, these components may be integrated as a single component or two components.

FIG. 3 is a series of diagrams 300 depicting an implementation of a catheter 104 assembly that may be used to provide end caps 202, projectiles 204, and other materials into a wellbore. In some implementations, the conduit 104 assembly may include two or more drill rod assemblies that may be attached to each other, thereby connecting the swivel 106 to the BHA 114. Fig. 3 depicts a catheter 104 assembly comprising an inner first catheter 104 (1) and an outer second catheter 104 (2) positioned concentrically around the first catheter 104 (1). The annulus 122 (1) is positioned between the first conduit 104 (1) and the second conduit 104 (2). In some cases, a third conduit 104 (3), such as a fuel line, may be used to transport the propellant material to the BHA 114. The third conduit 104 (3) may be positioned in the annulus 122 (1) between the first conduit 104 (1) and the second conduit 104 (2). In some implementations, the second conduit 104 (2) may be similar to a tubular drill pipe, such as "HXQ drill pipe" produced by bourt Longyear. For example, one or more of the conduits 104 may be made of high strength steel (e.g., having a yield strength of 110,000psi or greater).

The outer second conduit 104 (2) may include a threaded connection 302, such as a double shoulder threaded connection, that may hold a pressure of 6,000psi or greater and transmit a torque of 3,000ft-lb or greater. The threaded connection 302 may enable the inner and outer diameters of the connection sections of the conduit 104 to meet in a flush connection. For example, in addition to using threads, the threaded connection 302 may also include an internal shoulder 304 that mates with an external shoulder 306.

The inner first conduit 104 (1) may have a fixed end coupling at one end and a floating end coupling at the other end. The coupling or another portion of the first conduit 104 (1) may include fins, ribs, or other centralizers 308. In some implementations, one or more rings 310 may be formed on the centralizer 308. For example, the ring 310 may be received between the inner shoulder 304 and the outer shoulder 306 to provide axial restraint to the first conduit 104 (1). In some implementations, the floating end coupling may be biased using a spring 312 and a collar 314. For example, the spring 312 may allow the floating end coupling to move axially and rotationally, but also axially and rotationally bias the floating end coupling. Collar 314 may be attached to first conduit 104 (1) and may serve as a support for spring 312. In some implementations, the fixed end coupling may include a first portion of the third conduit 104 (3), such as a raised stringer on one side thereof. The floating end coupling may have a second portion of the third conduit 104 (3), such as a mating or complementary stringer. One or both of the floating end coupling or the fixed end coupling may include a stringer extension including a third portion of the third conduit 104 (3). The mating of the fixed end coupling and the floating end coupling may also mate portions of the third conduit 104 (3) to form a passageway outside of the first conduit 104 (1) (e.g., within the annulus 122 (1)) that may be used to provide propellant material to the BHA 114.

As shown in the lower portion of fig. 3, the third conduit 104 (3) may include a passage 316 to convey propellant material from a source of propellant material to the BHA 114. In some implementations, the channel 316 may be sealed by a valve 208 (3), such as a poppet valve. The poppet valve may be configured to prevent release of the propellant material before a first side of the poppet valve positioned within the first portion of the third conduit 104 (3) engages a mating second side of the poppet valve positioned within the second portion of the third conduit 104 (3). In some implementations, a sealing member 318, such as a face seal or O-ring, may prevent leakage of propellant material from the third conduit 104 (3) when the two sides of the poppet valve are mated. One or both sides of the poppet valve may be biased using one or more springs 312 that maintain the poppet valve in a closed position prior to mating of the sides of the poppet valve.

In some implementations, at least a portion of the third conduit 104 (3) may include a tube or hose. For example, a flexible conduit 104 (3), such as a tube or hose, may be coiled between two portions of the first conduit 104 (1) to allow for deflection that may be caused by axial or rotational travel of the first conduit 104 (1). In some implementations, the third conduit 104 (3) may be attached to the first conduit 104 (1) by one or more of: brazing, swaging, threaded hydraulic fittings, flared fittings, compression fittings or ferrule-based fittings such as those provided by Swagelok Company, or other types of couplings.

When the threaded connection 302 of the second conduit 104 (2) is connected, the floating end coupling of the first conduit 104 (1) may rotate. When the portion of the third conduit 104 (3) extending from the floating coupling contacts the portion of the third conduit 104 (3) on the fixed end coupling, the portion is prevented from rotating and may move axially toward other portions of the third conduit 104 (3). When the sealing surfaces of valve 208 (3) contact during this process, valve 208 (3) resists further axial advancement and spring 312 is compressed. The contact force may also cause the sealing member 318 to form a seal. Contact between the two sides of the poppet valve may allow fluid to flow from one side of the third conduit 104 (3) to the other.

As previously described, in some embodiments, the additional conduit 104 may be positioned around the second conduit 104 (2). In this case, the additional conduit 104 may comprise a threaded connection, while the first conduit 104 (1) and the second conduit 104 (2) comprise a socket-type connection. In this implementation, an additional annulus 122 (2) is defined between the second conduit 104 (2) and the third conduit 104 (3). In some implementations, the first annulus 122 (1) may be used to remove air or another gas from a portion of the conduit interior 126 to the surface, such as by venting the gas to ambient pressure at the wellbore surface. In other cases, the annulus 122 may vent gas to a sub-ambient pressure region. For example, air pressure may be used within the first conduit 104 (1) to perform one or more functions, such as burning propellant material or moving the end cap 202 and projectile 204. After the end cap 202 has been placed as a barrier to isolate the conduit interior 126 from the wellbore environment, the pressure within the conduit 104 (1) may be reduced by flowing air into the annulus 122 in pressure communication with the surface, which may reduce the pressure within the conduit 104 (1) to about atmospheric pressure.

As previously described, the conduit 104 may be connected to the BHA 114 and deliver gas, propellant material, end cap 202, projectile 204, drilling fluid or other fluids, and other materials to the BHA 114.

FIG. 4 is a diagram 400 depicting an implementation of a Bottom Hole Assembly (BHA) 114 and an associated string of conduits 104. As described with respect to fig. 1 and 2, the swivel 106 at the surface of the wellbore may include one or more inlets for receiving air or another gas and may also receive the end cap 202 and the projectile 204, one or more inlets for receiving propellant material, and one or more inlets for receiving water, drilling fluid, or other fluids. The material provided into the inlet may flow through the string of conduits 104. In particular, the first conduit 104 (1) may be concentrically positioned within the second conduit 104 (2). The first annulus 122 (1) may be defined between the first conduit 104 (1) and the second conduit 104 (2). The second annulus 122 (2) may be defined between the second conduit 104 (2) and the wellbore wall 402. In some implementations, the additional conduit 104 may be positioned concentrically around the second conduit 104 (2), and the second annulus 122 (2) may be positioned between this additional conduit 104 and the second conduit 104 (2). In this case, there may be an additional annulus 122 between the additional conduit 104 and the wellbore wall 402. In some implementations, the third conduit 104 (3) may extend axially within the first annulus 122 (1). For example, the conduit interior 126 of the first conduit 104 (1) may be used to flow air or another gas, the end cap 202, and the projectile 204 to the BHA 114. The third conduit 104 (3) may be used to provide propellant material to the BHA 114. The first annulus 122 (1) may be used to provide water or drilling fluid to the drill bit 102 and the second annulus 122 (2) may be used to receive water or drilling fluid and debris diverted by the drilling fluid. In other implementations, such as when the additional conduit 104 is positioned around the second conduit 104 (2), the first annulus 122 (1) may be used to flow air removed from the BHA 114 to the surface, while the second annulus 122 (2) and additional annulus 122 may be used to flow water or drilling fluid into and out of the drill bit 102.

A conduit connector 404, such as one or more threaded connectors, couplings, rings, etc., may be used to engage portions of the conduit 104 with one another. Although fig. 4 depicts a single conduit connector 404, any number and type of connectors between portions of the conduit 104 may be used. One or more of the conduits 104 may engage a BHA manifold 406, which may include one or more inlets, outlets, valves, filters, pumps, etc. that may control the supply of air or gas, end cap 202, projectile 204, propellant material, water, or fluid to the BHA 114. For example, a portion of the first conduit 104 (1) extending from the BHA manifold 406 may transport air or another gas, the end cap 202, and the projectile 204 from the BHA manifold 406 through the gas diverter 408 to a portion of the first conduit 104 (1) that includes a preloaded tube 410 in which the end cap 202 and the projectile 204 may be retained. The preloaded tube 410, which is depicted and described in more detail below with reference to fig. 5, may be used as an air cushion to receive the end cap 202 and the projectile 204 without damaging the end cap 202 and the projectile 204 or causing significant collisions between the end cap and the projectile. For example, the flow of gas through the portion of the first conduit 104 (1) including the preload tube 410 may be prevented or restricted, such as by closing one or more valves 208 (4), resulting in the gas from the gas diverter 408 diverting around the preload tube 410. A portion of the first conduit 104 (1) including the metering tube 414, depicted and described in more detail below with respect to fig. 5 and 6, may receive the separate end cap 202 and projectile 204 from the preloaded tube 410, such as by actuating a movable finger, latch, or other type of member protruding into the conduit interior 126. By actuating the movable member, the individual end cap 202 or projectile 204 may be moved from the preloaded tube 410 into the metering tube 414. Additional end caps 202 or projectiles 204 may be prevented from entering the metering tube 414, while actuation of the movable member may enable the end caps 202 or projectiles 204 within the metering tube 414 to pass through the first valve 208 (4) into the air lock 206. The first valve 208 (4) of the air lock 206 may be closed while the second valve 208 (5) is opened to admit the end cap 202 or projectile 204 into a portion of the first conduit 104 (1) including the breech pipe 416.

The end cap 202 within the breech pipe 416 may access a portion of the first conduit 104 (1) including a launch tube 418 positioned between the breech pipe 416 and the drill bit 102. The end cap 202 may engage an end cap retaining mechanism 420, which is depicted and described in more detail below with respect to fig. 11. The end cap retaining mechanism 420 may be positioned within the launch tube 418 or at an end of the launch tube 418, and may include latches, fingers, or other types of movable members that may extend into the catheter interior 126 to contact the end cap 202.

End cap 202 may isolate the firing tube 418 from the wellbore environment. The projectile 204 may then pass from the preloaded tube 410 through the metering tube 414 and the air lock 206 to enter the breech tube 416. At least a portion of the air or other gas within the breech tube 416 and the launch tube 418 may be removed, such as by removing the vented gas 422 into the annulus 122 (1) using one or more valves 208 (6). In other implementations, the annular pump, depicted and described in more detail with respect to fig. 9, may engage the firing tube 418 or another portion of the first conduit 104 (1), and may remove gas from within the breech tube 416 and the firing tube 418.

The propellant line 424 or a portion of the third conduit 104 (3) may provide propellant material from the BHA manifold 406 to the breech pipe 416. For example, the propellant material may include a combustible material that may apply a force to the projectile 204 within the breech pipe 416 to accelerate the projectile 204 through the launch tube 418, through an opening in the drill bit 102, and into contact with geological material located adjacent the drill bit 102. In some implementations, the projectile 204 may pass through the end cap 202, at least partially degrading, weakening, or breaking the end cap 202. The diverting gas 412 from the gas diverter 408 may be provided to the breech tube 416 to facilitate ignition or combustion of the propellant material. For example, the turning gas 412 may include air or another gas having sufficient oxygen to enable ignition or combustion of the propellant material. Continuing with the example, an igniter 426 associated with the breech tube 416 may ignite or otherwise initiate combustion of the propellant material.

Electric or hydraulic valves may be used to actuate the various components of the BHA 114 shown in fig. 4. For example, drilling fluid or another separate hydraulic fluid may be used to actuate each of the following: a valve controlling a pump that controls the transport of propellant material from BHA manifold 406 to breech pipe 416; a valve actuator controlling a valve 208 of the damper 206; a valve actuator controlling one or more valves 208 that regulate the flow of gas from the gas diverter 408 to the breech pipe 416; a valve 208 for removing gas from the emitter tube 418, and the like. An electric or hydraulic valve or other controller may also be used to control the movable components within the metering tube 414 and end cap retaining mechanism 420.

For example, drilling fluid or another fluid from the swivel 106 may be delivered to the BHA 114 via various circuits in the string of conduits 104. A shaker, hydrocyclone, centrifuge, screen, etc. may be used to recirculate, filter drilling fluid or other fluids, and in some cases, one or more downhole filters within the BHA 114 or string of conduits 104 may be used to filter fluids, remove debris, etc. Drilling fluid may be discharged through injectors or nozzles associated with the drill bit 102 and circulated through the annulus 122 toward the surface. For example, a pressure within the BHA 114 that is greater than a pressure within the annulus 122 may be used to move fluid through a jet or nozzle to the annulus 122. In some cases, a portion of the fluid may be diverted to regulate the release of gas, propellant material, water, drilling fluid, or the like using the control valve 208. For example, valve 208 may be selectively opened to release drilling fluid or water, air, another gas, or the like; flush breech tube 416 and firing tube 418; removing debris after accelerating the projectile 204; placing end cap 202 within launch tube 418; placing the projectile 204 within the breech tube 416; the breech tube 416 is filled with propellant material and gas for combustion, etc.

In some implementations, the BHA 114 may include a control system that may control relays, solenoids, servo systems, servo motors, or other control mechanisms. The control system may receive input from sensors such as flow switches, pressure relays or transducers, temperature transducers or thermocouples, limit switches, proximity or position switches or transducers, resistivity sensors, ultrasonic sensors, or other sensors that may provide input indicative of the state of the system 100. The controller may use input from the sensors to provide signals to the various components based on logic embedded in the controller. For example, pressure may be sensed to determine when the breech pipe 416 has reached an amount of pressure suitable for accelerating the projectile, a limit switch or proximity sensor may determine whether the end cap 202 or projectile 204 has entered or exited the air lock 206, an ultrasonic sensor may determine whether an object within the air lock 206 is the end cap 202 or the projectile 204, a limit switch or position sensor may identify whether the valve 208 is open or closed, a pressure sensor, proximity sensor or limit switch may determine whether the end cap 202 has reached a selected position within the launch tube 418, a flow switch may indicate whether the system 100 is ready for use or should be placed in a non-operational mode, and so forth.

The controller may include a microprocessor or Programmable Logic Controller (PLC) that may control a number of functions, such as opening and closing of the valve 208, actuation of the igniter 426 to ignite the propellant material and cause acceleration of the projectile 204, and so forth. The controller may be housed in a sealed pressure chamber or other type of housing that is fluidly isolated from the wellbore by a high pressure feedthrough that can transmit sensor inputs and control signals to and from the housing. In some implementations, the control system may be powered by a battery or other type of power source that may be housed in a pressure chamber or other type of housing associated with the BHA 114. In other implementations, the power may be provided using a generator within the BHA 114, a turbine driven by drilling fluid, a battery recharged or replenished by a downhole generator, and the like.

In some implementations, the system 100 may be associated with a hydraulic control system that uses hydraulic fluid instead of drilling fluid or another fluid provided by an inlet in the swivel 106 to actuate a valve and perform other functions. For example, hydraulic fluid may be stored in a downhole reservoir, pumped using one or more downhole pumps powered by electricity or a downhole turbine, circulated through the system 100 and recirculated to the reservoir, and so forth.

In some implementations, the propellant material may include diesel or another hydrocarbon that may be pressurized by a pump associated with the BHA 114 to a pressure sufficient for combustion, such as a pressure ranging from 5000psi to 30000psi, depending on the downhole temperature. Propellant material may be injected into the breech tube 416 at or near the time air or another diverting gas 412 is released into the breech tube 416 to promote mixing of the propellant material with the gas. In some implementations, a combination of a downhole pump and a surface pump may be used to provide propellant material into the breech tube 416. For example, a downhole pump may provide most of the pressure for injecting the propellant material, while a pump at the surface is used to overcome the fluid friction of pumping the propellant material through the third conduit 104 (3). Continuing with the example, depending on the size of the third conduit 104 (3) and the depth of the wellbore, the pressure required to overcome fluid friction at the surface may be in the range of 300psi to 3000 psi. In other implementations, one or more pumps at the wellbore surface may be used to apply the greater pressure. In some implementations, one or more additives may be added to the propellant material to enhance combustion, reduce atomization requirements, and reduce the pressure required therefor.

In other implementations, the propellant material may include, but is not limited to, hydrogen, propane, butane, liquid fuels (such as hydrocarbons, etc.), solid gas generators that can produce propellants or oxidants, or explosive materials. For example, one implementation may utilize air as the oxidant and another gas as the propellant material, such as hydrogen. Other implementations may use a propellant material or oxidizer that is liquid under pressure but gaseous at ambient conditions, such as propane or butane as the propellant material, nitrous oxide as the oxidizer, and the like, within the embodiments. In some implementations, a compressed liquid may be incorporated into one or more projectiles 204 and the portion of projectile 204 including the material may be pierced or otherwise accessed to release the material as a gas. In another implementation, the solid gas generator may be incorporated into the body of the projectile 204 or supplied in unison with the end cap 202 or the projectile 204. The solid gas generator may generate a propellant material after activation, which in some cases may limit or eliminate the need for the third conduit 104 (3) or the propellant line 424. In other implementations, the solid gas generator may generate an oxidizing agent for use in conjunction with the propellant material, thereby limiting or eliminating the need to provide air or another oxidizing gas into the breech tube 416. In other implementations, solid explosives may be used to accelerate the projectile 204, which may limit or eliminate the need to provide propellant material or gas into the breech tube 416. The explosive material may be included within the body of the projectile 204 or provided separately into the breech tube 416.

FIG. 5 is a diagram 500 depicting an implementation of the gas diverter 408, the pre-load tube 410, the metering tube 414, and the air brake 206 within the Bottom Hole Assembly (BHA) 114. As previously described, the end cap 202 and the projectile 204 may be provided from the swivel 106 to the BHA 114 via the first conduit 104 (1), such as by using air or another gas to move the end cap 202 and the projectile 204 through the first conduit 104 (1) to the preloaded tube 410. In some cases, the velocity of the end cap 202 and the projectile 204 within the first conduit 104 (1) may be sufficient to potentially damage or destroy the end cap 202 or the projectile 204 when propelled using an air stream. In this case, the pre-load tube 410 may be used to limit or prevent damage to the end cap 202 and projectile 204, such as by slowing the velocity of the object as it reaches and enters the pre-load tube 410. For example, the gas diverter 408 may use the gas diversion port 502 to divert gas for moving the end cap 202 and the projectile 204. The diverting gas 412 may be flowed through the gas channel 504 from the gas diverter 408 to bypass the damper 206 to the breech pipe 416, thereby delivering air or another gas for use in the BHA 114. The gas diverter 408 may include a screen, filter, or other barrier that prevents the end cap 202 or projectile 204 from entering the inlet of the gas channel 504 or getting stuck on the inlet. Thus, the end cap 202 and projectile 204 may pass through the gas diversion port 502 and into the preloaded tube 410. The pre-load tube 410 may include a generally cylindrical channel that holds at least one end cap 202 or projectile 204, but in some implementations, ten or more end caps 202 and projectiles 204 may be held. Storing the plurality of end caps 202 and the projectile 204 within the preloaded tube 410 may enable feeding the end caps 202 and the projectile 204 from the surface independent of the time the projectile 204 is accelerated to extend the wellbore. The pre-load tube 410 may limit or prevent damage to the end cap 202 and the projectile 204 by acting as an air cushion (such as a blind cavity with a substantially small gap between the outer diameter of the end cap 202 and the inner diameter of the pre-load tube 410) such that the air and limited gap within the pre-load tube 410 can slow the movement of the end cap 202 and the projectile 204.

To facilitate maintaining the pre-load tube 410 as a blind cavity, a damper 206 that controls the flow of gas beyond the pre-load tube 410 may be used. The airlock 206 may include an upper first valve 208 (4) and a lower second valve 208 (5) located on opposite sides of the airlock chamber. In operation, at least one of the valves 208 associated with the damper 206 may be closed at a given time. The first valve 208 (4) may be primarily subjected to pressure differences from above, such as the pressure from the portion of the conduit 104 (1) above the valve 208 (4) being greater than the pressure below the valve 208 (4). The second valve 208 (5) may at least partially restrict the flow of gas between the damper 206 and the breech pipe 416. However, the gas passing through the second valve 208 (5) may be removed from the breech pipe 416 and the launch pipe 418 using the valve 208 (6) (shown in fig. 4) to vent the gas into the annulus 122 (1), or using an annular pump.

In one implementation, the end cap 202 may be moved using gas pressure to isolate the firing tube 418 from the wellbore environment. In this case, the air pressure from the air moving through the first conduit 104 (1) may be greater than the drilling fluid pressure at the drill bit 102, which may be based in part on the hydrostatic pressure in the wellbore and the rate at which the drilling fluid returns to the surface via the annulus 122. For example, if the wellbore has a depth of 1000 meters, the fluid pressure at the drill bit 102 may be about 3000psi. In this case, the air pressure above the air lock 206 may thus be 3000psi or greater when the breech pipe 416 and the launch tube 418 are at least partially evacuated due to the removal of air therefrom. When the first valve 208 (4) is open and the second valve 208 (5) is closed and the breech pipe 416 and the launch pipe 418 are at least partially evacuated, the pressure differential across the second valve 208 (5) may be 3000psi or higher. However, when the projectile 204 is accelerated, such as by burning a propellant material, the pressure below the second valve 208 (5) may increase. For example, acceleration of the projectile 204 may result in a pressure of 10000psi or greater below the second valve 208 (5). In some implementations, the first valve 208 (4) may be unidirectional (e.g., capable of withstanding pressure from one direction) while the second valve 208 (5) is bidirectional (e.g., capable of withstanding pressure from both directions).

Although fig. 5 depicts the damper 206 including two valves 208, in other implementations, the damper 206 may include three valves 208. For example, the uppermost valve 208 and the intermediate valve 208 may be unidirectional, each oriented to withstand greater pressure from above. The lower valve 208 may be unidirectional, oriented to withstand greater pressure from below. In this case, the upper and middle valves 208 may be configured to withstand a lower pressure, such as 4000psi, than a single valve performing the same function, while the lower valve 208 may be configured to withstand a greater pressure, such as 12000psi. In this case, the lower valve 208 may protect the upper and middle valves 208 from the transient increase in pressure that may occur when the projectile 204r is accelerated. Because the torque used to actuate the ball valve increases with the pressure level of the valve, using two valves 208 configured to withstand lower pressures may reduce the torque required to actuate the valves 208, which may reduce the demands on the valve actuation components of the system 100.

Although fig. 5 depicts the valves 208 as ball valves, in other implementations, one or more of the valves 208 may comprise a flapper valve, or other type of valve capable of fitting within the string of conduits 104 and withstanding the pressure within the conduits 104.

As described with respect to fig. 4, the metering tube 414 may be located below the preload tube 410 and above the air lock 206 to enable a single end cap 202 or projectile 204 to be moved from the preload tube 410 into the air lock 206. The metering tube 414 may include a first latch 506 (1) or set of latches positioned on a first side of the metering tube 414 proximate the preload tube 410 and a second latch 506 (2) or set of latches positioned on a second side of the metering tube 414 proximate the damper 206. A propellant passage 508 may extend through the BHA 114 through the gas diverter 408, which may be used to provide water, drilling fluid, or other fluids to the drill bit 102, or in some implementations, to receive gas discharged from the firing tube 418. One or more control valves may be used downstream of the damper 206, such as a valve 208 (7) for controlling the flow of gas from the gas channel 504 into the breech pipe 416, and a valve 208 (8) for controlling the flow of fluid or other material from the propellant channel 508 into the breech pipe 416 or from the breech pipe 416. The selective opening and closing of the control valve may allow gas or drilling fluid to enter the breech pipe 416 and protect the upstream conduit 104 from exposure to high pressure during combustion of the propellant material to accelerate the projectile 204.

FIG. 6A is a diagram 600 depicting an isometric disassembled view of an implementation of the metering tube 414 within the Bottom Hole Assembly (BHA) 114. As previously described, the metering tube 414 may sequentially operate the latches 506 to enable a single end cap 202 or projectile 204 to enter the metering tube 414 from the preloaded tube 410, then enter the air lock 206 from the metering tube 414 and finally the breech tube 416. Metering tube 414 may include an inner sleeve 602 positioned within an outer sleeve 604. A set of upper first latches 506 (1) may engage a first end of the inner sleeve 602 using a hinge 606 or other type of mechanism that may enable the latches 506 (1) to move between a first position that at least partially blocks an interior of the inner sleeve 602 and a second position that does not block the interior or blocks the interior less than when in the first position. A set of lower second latches 506 (2) may engage the second end of inner sleeve 602 and may also be movable between a first position at least partially blocking the interior of inner sleeve 602 and a second position. Mounting the set of latches 506 on the hinge 606 enables the latches 506 to be actuated by moving the outer sleeve 604 relative to the inner sleeve 602 (e.g., to a first position to at least partially block the inner sleeve 602). For example, moving the outer sleeve 604 upward relative to the inner sleeve 602 may actuate the first latch 506 (1) that may protrude into the interior of the metering tube 414 through the opening 608 in the sleeve. Moving the outer sleeve 604 downward relative to the inner sleeve 602 may actuate the second latch 506 (2) while enabling the first latch 506 (1) to retract at least partially from the interior of the metering tube 414.

When actuated to protrude into the interior of the metering tube 414, a set of latches 506 may inhibit movement of the end cap 202 and projectile 204 through the string of conduit 104. In some implementations, one of the first latch 506 (1) or the second latch 506 (2) may be actuated at a given time while the other set of latches 506 is deactivated. In other implementations, both sets of latches 506 may be actuated simultaneously, depending on the spacing between the openings 608 in the sleeve. Although fig. 6A depicts two latches 506 within each set, any number of latches 506 may be used, including a single latch 506 or more than two latches 506. Additionally, while FIG. 6A depicts the latch 506 secured using a hinge 606, in other implementations, any mechanism that enables the latch 506 to move into and out of the interior of the metering tube 414 may be used, including (without limitation) pins, cams, rails, gears, pistons, or collets. Further, while fig. 6A depicts the outer sleeve 604 moving axially relative to the inner sleeve 602 to actuate the latch 506, in other implementations, the other sleeve 604 may move rotationally relative to the inner sleeve 602, or other mechanisms may be used to move the latch 506, such as cams, linkages, push rods, gears, pistons, hydraulic actuators, and the like.

Fig. 6B is a series of diagrams 610 depicting side, front and cross-sectional views of the metering tube 414 of fig. 6A in upper and lower actuated positions. For example, one sequence in which metering tube 414 may be operated may include the following sequence:

the series of alternating end caps 202 and projectiles 204 within the preloaded tube 410 are restrained from moving into the metering tube 414 by the actuated upper latch 506 (1). Fig. 6B depicts four views of the metering tube 414 depicting the actuated upper latches 506 (1) labeled "front view-upper latch actuation", "side view-upper latch actuation", "front cross-sectional view-upper latch actuation" and "side cross-sectional view-upper latch actuation".

The upper latch 506 (1) may then be deactivated while the lower latch 506 (2) is activated. In other implementations, the lower latch 506 (2) may be in the actuated position before the upper latch 506 (1) is deactivated. In some cases, the upper latch 506 (1) and the lower latch 506 (2) may be configured such that deactivation of one set of latches 506 results in actuation of the other set of latches, and vice versa, such that both sets of latches 506 are not deactivated at the same time. Deactivation of the upper latch 506 (1) may enable the end cap 202 to enter the metering tube 414 from the pre-load tube 410. Fig. 6B depicts four views of the metering tube 414, which depicts the actuated lower latches 506 (2) labeled "front view-lower latch actuation", "side view-lower latch actuation", "front cross-sectional view-lower latch actuation", and "side cross-sectional view-lower latch actuation".

The lower latch 506 (2) may then be deactivated to allow the end cap 202 to move toward the closed upper valve 208 (4). The upper latch 506 (1) may be actuated to block the projectile 204 from entering the metering tube 414. The upper valve 208 (4) of the damper 206 may then be opened to allow the end cap 202 to enter the damper 206. The upper valve 208 (4) may then be closed, separating the damper 206 containing the end cap 202 from the metering tube 414.

The upper latch 506 (1) may be deactivated and the lower latch 506 (2) may be activated to allow the projectile 204 to enter the metering tube 414 to contact the lower latch 506 (2). The lower latch 506 (2) may then be deactivated to allow the projectile 204 to move toward the air lock 206 while the upper latch 506 (1) is activated to prevent the subsequent end cap 202 from entering the metering tube 414. The closed upper valve 208 (4) of the air lock 206 may prevent further movement of the projectile 204.

The lower valve 208 (5) may be opened to release the end cap 202 into the breech tube 416, and the end cap 202 may be moved into the firing tube 418 to engage the end cap retaining mechanism 420. The end cap 202 may isolate the interior of the emitter tube 418 from the wellbore environment.

The lower valve 208 (5) of the air lock 206 may be closed and the upper valve 208 (4) of the air lock 206 may be opened to enable the projectile 204 to enter the air lock 206. The lower valve 208 (5) may be opened to allow the projectile 204 to enter the breech pipe 416. Valve 208 (6) in the firing tube 416 may be actuated to remove gas from the breech tube 416 and the firing tube 418. In other implementations, one or more pumps may be used to remove gas from the breech tube 416 and the launch tube 418. Propellant material and diverting gas 412 may then be provided into the breech tube 416, and combustion of the propellant material may apply a force to the projectile 204 that accelerates the projectile 204 toward the end cap 202 and then out of the launch tube 418 to contact the geological material. The drill bit 102 may be used to drill through material weakened by contact with the projectile 204.

The process described with respect to fig. 6B may be repeated for a plurality of end caps 202 and projectiles 204 provided into the preloaded tube 410 such that the projectiles are able to accelerate substantially continuously to contact the geological material.

Fig. 7 is a diagram 700 depicting an isometric cross-sectional view of one implementation of the configuration of the valve 208 within the breech tube 416. As previously described with respect to fig. 5, one or more valves 208 may be used to selectively introduce the diverting gas 412 from the gas diverter 408 or fluid from the propellant channel 508 into the breech pipe 416 or into the drill bit 102. In the implementation shown in fig. 7, two control valves 208 (7), 208 (8) are shown for moving gas or fluid into or out of the breech pipe 416, however in other implementations other numbers of valves 208 may be used. In some implementations, the valve 208 may be driven by a pushrod driven piston hydraulically actuated by a solenoid or servo mechanism.

The first valve 208 (7) separating the gas passage 504 from the breech pipe 416 may be used to control the flow of air or another gas into the breech pipe 416 in order to facilitate ignition and combustion of the propellant material. Air or another gas may also be flowed into the breech tube 416 to flush cuttings or other debris in the breech tube 416 or the launch tube 418, which may have flowed into the launch tube 418 or the breech tube 416 after the projectile 204 has been accelerated. Air or another gas may additionally be flowed into the breech tube 416 to move the end cap 202 through the breech tube 416 toward the end cap retaining mechanism 420.

The second valve 208 (8), which separates the propellant passage 508 from the breech pipe 416, may be used to control the flow of water, drilling fluid or one or more other fluids into the breech pipe 416. The fluid passing through the second valve 208 (8) may be used to flush cuttings or other debris in the breech pipe 416 or the launch pipe 418 in a similar manner as described with respect to the first valve 208 (7).

The first valve 208 (7) and the second valve 208 (8) may be closed and one or more other valves 208 (6) may be opened to at least partially empty the breech tube 416 and the launch tube 418 after positioning the end cap 202 and the projectile 204. The valve 208 may also be opened to provide propellant material into the breech tube 416.

The port 702 connecting the first valve 208 (7) and the second valve 208 (8) to the breech pipe 416 may be configured with an opening smaller than the end cap 202 or the projectile 204 in order to prevent the end cap 202 or the projectile 204 from partially entering the rear port 702 or being caught by the edges of the port. For example, fig. 7 depicts a port 702 having a shape including a plurality of vertical openings.

As described with respect to the valve 208 associated with the damper 206, the control valve associated with the breech pipe 416 may be configured to maintain an upstream air or fluid pressure when the breech pipe 416 is in an at least partially evacuated state. For example, the pressure above the valve 208 may be in the range of 2000psi to 3000psi higher than the pressure below the valve 208. However, when the projectile 204 is accelerated by burning the propellant material, the pressure within the breech tube 416 may reach 10000psi or more. Thus, in some embodiments, the valve 208 may be configured such that higher pressure in the breech pipe 416 may drive the valve 208 in a direction that results in a higher sealing contact pressure on the valve seat. The valve 208 may be spring biased such that there is sufficient valve seat contact pressure during acceleration of the projectile 204. For example, fig. 7 depicts the first valve 208 (7) and the second valve 208 (8) biased using one or more springs 704, such as coil springs or belleville springs. However, in other implementations, other types of springs may be used, such as coil springs, or other types of biasing members.

FIG. 8 is a flow chart 800 depicting an implementation of a method for providing end cap 202, projectile 204, and propellant material into a conduit string and extending a wellbore using projectile 204 and drill bit 102. At block 802, a plurality of end caps 202 and projectiles 204 arranged in an alternating fashion may be provided into the interior of the first conduit 104 (1). As described with respect to fig. 2, the container 108 containing one or more end caps 202 and projectiles 204 arranged in an alternating fashion may be placed in communication with an inlet within the swivel 106 assembly. The container 108 may have a horizontal orientation, such as that shown in fig. 2, from which individual end caps 202 and projectiles 204 may be sequentially provided into the conduit 104 (1). In other implementations, the container 108 may have a vertical orientation and multiple end caps 202 and projectiles 204 may be provided in close temporal proximity into the conduit 104 (1). In still other implementations, the container 108 may be positioned on the ground or another surface near the swivel, and a hose or other conduit may communicate the end cap 202 and the projectile 204 into the conduit 104 (1).

At block 804, gas may be provided into the first conduit 104 (1) to move the end cap 202 and the projectile 204 to the pre-load tube 410. For example, the swivel 106 assembly may include a gas inlet 110 (2) that may be used to provide air or another gas from a gas source into the interior of the first conduit 104 (1). Gas flow may be used to move the end cap 202 and projectile 204 through the conduit 104 (1) toward the preloaded tube 410. As described with respect to fig. 5, one or more valves 208 (4) may separate the preload tube 410 from the breech tube 416 while diverting gas through the gas passage 504 around the valve 208 (4), thereby enabling the preload tube 410 to function as a cushion of gas that may prevent damage to the end cap 202 and the projectile 204 by slowing the movement of the end cap 202 and the projectile 204.

At block 806, a first set of latches 506 (1) in the metering tube 414 adjacent to the preload tube 410 may be opened to enable the end cap 202 to reach the metering tube 414 from the preload tube 410. As described with respect to fig. 5 and 6, the end cap may contact the second set of latches 506 (2) and be retained in the metering tube 414 while preventing further advancement of the projectile 204 following the end cap 202 in the pre-load tube 410 through the conduit 104 (1). In some implementations, the second set of latches 506 (2) and the first set of latches 506 (1) may operate in conjunction with each other such that deactivation of one set of latches 506 causes actuation of the other set of latches, and vice versa. For example, fig. 6 depicts an implementation in which multiple sets of latches 506 are actuated by movement of an outer sleeve 604 relative to an inner sleeve 602. In other implementations, the sets of latches 506 may operate independently, such as through the use of hydraulic or other actuation methods.

At block 808, the first set of latches 506 (1) may be closed and the second set of latches 506 (2) may be opened to enable the end cap 202 to enter the breech tube 416. Closing the first set of latches 506 (1) may prevent the projectile 204 following the end cap 202 from advancing as the end cap 202 moves into the breech tube 416. As described with respect to fig. 5, in some implementations, the end cap 202 may pass through the damper 206 positioned between the metering tube 414 and the breech tube 416.

At block 810, gas may be provided into the breech tube 416 to move the end cap 202 to the end cap retaining mechanism 420 within the launch tube 418. As described with respect to fig. 5 and 7, the control valve 208 may be operated to control the airflow around the damper 206 and into the breech pipe 416 to provide movement to the end cap 202. As described with respect to fig. 4, the end cap retaining mechanism 420 may be positioned within or at the end of the launch tube 418 and may include a latch, finger, or other type of movable member that may extend into the catheter 104 (1) to contact the end cap 202. The end cap retention mechanism 420 is depicted and described in more detail below with respect to fig. 11.

At block 812, a first set of latches 506 (1) in the metering tube 414 may be opened to enable the projectile 204 following the end cap 202 to enter the metering tube 414 from the preloaded tube 410. The second set of latches 506 (2) may be closed and the projectile 204 may be prevented from moving further toward the breech tube 416. The body of the projectile 204 may prevent further advancement of the subsequent end cap 202 into the metering tube 414.

At block 814, the first set of latches 506 (1) may be closed and the second set of latches 506 (2) may be opened to enable the projectile to enter the breech tube 416. Closing the first set of latches 506 (1) may prevent further advancement of the subsequent end cap 202 toward the breech tube 416 as the projectile 204 moves into the breech tube 416. As described with respect to fig. 5, the projectile 204 may pass through the air lock 206 between the metering tube 414 and the breech tube 416. As described with respect to block 810, the gas provided into the breech tube 416 may also move the projectile 204 to a selected location, such as at or near the junction of the breech tube 416 and the launch tube 418.

At block 816, the damper 206 separating the breech pipe 416 from the upper portion of the first conduit 104 (1) may be closed, and the valve 208 (6) in the launch tube 418 or breech pipe 416 may be opened to allow gas to flow from the launch tube 418 and breech pipe 416 into the first annulus 122 (1) between the first conduit 104 (1) and the second conduit 104 (2) placed around the first conduit 104 (1). As described with respect to fig. 1, 2, and 4, in some implementations, the breech pipe 416 and the launch pipe 418 may be at least partially evacuated by removing gas into the first annulus 122 (1). For example, the first annulus 122 (1) may be in communication with the surface of the wellbore, and placing the breech pipe 416 and the launch tube 418 in pressure communication with the surface may enable higher pressures within the breech pipe 416 and the launch tube 418 to equilibrate with the surface pressure. After removing gas from breech pipe 416 and launch pipe 418, valve 208 (6) may be closed. In other implementations, the gas in the breech tube 416 and the launch tube 418 may be at least partially evacuated before moving the projectile 204 into the breech tube 416, such as after the projectile 204 has been moved into the air lock 206. Gas may be removed from the breech pipe 416 and the launch pipe 418 any time after the end cap 202 has isolated the launch pipe 418 from the wellbore environment and the breech pipe 416 from the rest of the conduit string, such as by closing one or more valves 208.

At block 818, a propellant material may be provided into the breech tube 416 through the third conduit 104 (3) extending through the first annulus 122 (1). For example, as shown in fig. 3 and 4, the third conduit 104 (3) may extend axially within the first annulus 122 (1) between the first conduit 104 (1) and the second conduit 104 (2) and may provide propellant material from a propellant material source to the breech tube 416. As described with respect to fig. 5 and 7, the one or more valves 208 may control the flow of propellant material into the breech pipe 416.

At block 820, a gas (such as air or another gas including oxygen) may be provided into the breech tube 416 by diverting the gas through a passage around the damper 206. For example, as described with respect to fig. 5, the gas diverter 408 may flow gas into the breech pipe 416 around the preload pipe 410, the metering pipe 414, and the damper 206. A valve 208 (7) between the gas passages 504 connecting the gas diverter 408 to the breech pipe 416 may be used to control the flow of gas to the breech pipe 416. The gas provided to the breech tube 416 may be used to facilitate combustion of the propellant material to accelerate the projectile 204. For example, the gas may include air, or another gas containing sufficient oxygen for the combustion reaction.

At block 822, the propellant material may be ignited, which may cause the propellant material to apply a force to accelerate the projectile 204 through the launch tube 418 and end cap 202 to contact the geological material. As previously described, the propellant material may mix with air within the breech tube 416 to enable the combustion reaction to be initiated, such as by actuating the igniter 426. The reaction of the propellant material may accelerate the projectile 204 through the launch tube 418. In some implementations, the launch tube 418 may include one or more internal features, such as internal baffles, rails, or other features that exert a ram effect when the projectile 204 is accelerated. As the projectile 204 passes through the end cap 202, the projectile 204 may at least partially break or weaken the end cap 202. The projectile 204 may pass through an opening in the drill bit 102 to contact the geological material. The geological material contacted by the projectile 204 may be at least partially weakened, degraded, broken, etc. The projectile 204 may be at least partially disrupted by interactions between the projectile 204 and the geological material. Thus, interactions between the projectile 204 and the end cap 202 and between the projectile 204 and the geological material may create debris, which may include portions of the end cap 202, the projectile 204, and the geological material.

At block 824, the drill bit 102 at the end of the firing tube 418 may be operated to extend the wellbore through the geological material contacted by the projectile 204. Geological materials weakened by interaction with the projectile 204 may be more readily penetrated using the drill bit 102, thereby reducing energy and mechanical wear associated with operation of the system 100 and enabling the wellbore to extend at a faster rate than conventional techniques. The interaction between the drill bit 102 and the geological material may create additional debris.

At block 826, drilling fluid may be provided to the drill bit 102 through the second annulus 122 (2) between the second conduit 104 (2) and a third conduit 104 disposed about the second conduit 104 (2). The drilling fluid may comprise an oil-based or water-based drilling fluid. In other implementations, water may be used in addition to or in lieu of drilling fluid. Drilling fluid may contact the drill bit 102 to cool and lubricate the drill bit 102. The drilling fluid may also displace cuttings and other debris within the wellbore.

At block 828, the gas provided through the first conduit 104 (1) or the fluid provided through the second annulus 122 (2) may be used to remove debris from the wellbore. For example, after the projectile 204 removes the end cap 202, air or another gas may be provided through the first conduit 104 (1), which may exit the distal end of the launch tube 418 and transfer debris. The diverted debris may be carried out of the wellbore through the first annulus 122 (1). Alternatively or additionally, drilling fluid provided into the wellbore through the second annulus 122 (2) may transfer debris into the third annulus between the outermost conduit 104 and the wellbore wall 402 or, in some cases, the additional conduit 104.

Fig. 9A is a diagram 900 depicting an exploded partial cross-sectional view of an implementation of a pump that may be used to remove gas or fluid from breech tube 416 or launch tube 418. Although fig. 4 depicts the use of the valve 208 (6) that allows gas to move from the breech pipe 416 and the transmitting pipe 418 into the annulus 122 (1), in some implementations, an annular pump may be used to remove gas or fluid from the breech pipe 416 and the transmitting pipe 418. The pump may include an annular piston 902 reciprocally movable within a piston housing 904. The piston housing 904 may include a fluid end 906, a cylinder section 908, and anti-rotation fingers 910. While anti-rotation fingers 910 are shown as open fingers 910, in other implementations, the pump may include other anti-rotation features, such as splines within the cylinder, or other mechanisms that allow axial movement while preventing rotational movement of the mating components.

The fluid end 906 may include one or more check valves 912 or other types of valves. One or more of the check valves 912 may be connected to the discharge tube 418 through at least one inlet port 914. The check valve 912 and inlet port 914 may allow gas or fluid to flow from a port in the launch tube 418 into the fluid end 906 of the pump. One or more of the check valves 912 or other types of valves may be used to control the flow of fluid between the BHA 114 and the adjacent annulus 122 through the associated outlet ports 920 of the pump.

In some implementations, the annular piston 902 may have one or more seals 922 (1) on its outer diameter that may seal the cylinder section 908 and one or more seals 922 (2) on its inner diameter that may seal the outer diameter of the launch tube 418. In other implementations, piston 902 may include piston rings, such as rings formed of ceramic material or hard metal (such as tungsten carbide), or may be made of or coated with such materials. In this case, the piston 902 may operate using only a single seal 922 or no sealing member.

The annular piston 902 may be attached to a cam body 926 that includes a cam track 928 about its circumference, such as by using threads 924 (1). The cam body 926 may include one or more splines, ribs 930, or other types of protrusions that may enable the cam body 926 to move in an axial direction but prevent rotation thereof. In some implementations, the cam track 928 may have a machined shape, such as a shape corresponding to a sine wave, such that acceleration at each end of the pump's stroke cycle is minimized. In some implementations, the cam body 926 may include multiple portions that may be attached to one another, such as by using threads 924 (2) (shown in fig. 9B) proximate the shoulder 925 (shown in fig. 9B), to provide a stop when the portions are threaded together. In some cases, the portions may be threaded together first, followed by machining of the cam track 928 to enable the opposing faces of the cam track 928 to separate and then assembled around the mating components.

The pump may include a roller drive bushing 932 mounted on a shaft pin 934, mounted on a rotary coupling 936 that may be driven by a turbine or other power source. For example, the turbine driving the pump may be a multi-stage axial flow turbine, similar to turbines that may be used to power a downhole turbine rig. While such turbines may include 100 or more turbine stages, FIG. 9A depicts a single exemplary turbine rotor 938, stator 940, rotating bearing 942, thrust bearing 944, disc springs 946, and thrust ring 948.

Fig. 9B is a series of diagrams 950 depicting side cross-sectional and assembly views of the pump of fig. 9A. In operation, the pump turbine may cause the turbine coupling 936 to rotate, thereby causing the sleeve 932 to orbit on the plate about the central axis of the pump. The bushing 932 may engage a face of the cam tracks 928 (1) and 928 (2), which may cause the cam body 926 to reciprocate. Because the cam body 926 is connected to the shoulder 925 and the annular piston 902, the piston 902 may also reciprocate. When the end cap 202 has been placed in the firing tube 418 to isolate the firing tube 418 from the wellbore environment, the pump may apply suction to the firing tube 418 and breech tube 416 to expel gas or fluid from the firing tube 418 and breech tube 416 into the adjacent annulus 122 (1).

In some implementations, the reciprocating motion of the cam body 926 may be used to impart motion to other components of the system. For example, the impact drilling mechanism may be engaged with the cam body 926 using one or more conduits 104 or other connectors such that axial movement of the cam body 926 may cause the mechanism to contact and fracture or displace geological materials, debris, and the like.

Fig. 10 is a diagram 1000 depicting a diagrammatic cross-sectional view of a conduit string including three conduits 104 and associated annulus 122 that may be used to provide gas, end caps 202, projectiles 204, and fluids into a wellbore and circulate the gas, fluids, and debris toward the surface of the wellbore. The first conduit 104 (1) may be positioned substantially concentrically within the second conduit 104 (2) such that a first annulus 122 (1) is defined between the first conduit 104 (1) and the second conduit 104 (2). The third conduit 104 (4) may be positioned substantially concentrically around the second conduit 104 (2) defining a second annulus 122 (2) between the second conduit 104 (2) and the third conduit 104 (4). A third annulus 122 (3) may be defined between an outer diameter of the third conduit 104 (4) and the wellbore wall 1002.

As previously described, the end cap 202 may be provided into the first conduit 104 (1) and may be moved through the conduit interior 126 using air or another gas provided into the first conduit 104 (1). The end cap 202 may contact an end cap retaining mechanism 420 in the portion of the first conduit 104 (1) that includes the launch tube 418. End cap 202 may isolate conduit interior 126 from the wellbore environment. As described with respect to fig. 8, the projectile 204 may be positioned within the breech pipe 416 of the first conduit 104 (1), and the valve 208 may isolate the breech pipe 416 and the launch pipe 418 from the portion of the first conduit 104 (1) located above the breech pipe 416. One or more valves 208 (6) may be used to evacuate at least a portion of the gas within the conduit interior 126 into the adjacent first annulus 122 (1). For example, the first annulus 122 (1) may be in communication with the surface of the wellbore and establishing communication between the surface and the conduit interior 126 by opening the valve 208 (6) may equalize the pressure at the conduit interior 126 and the wellbore surface.

In some implementations, the additional conduit 104 (3) may be positioned within the first annulus 122 (1) and used to provide propellant material into the breech tube 416. For example, after the breech pipe 416 and the launch tube 418 are evacuated by moving gas through the valve 208 (6), the propellant material and air for combustion may be used to cause a combustion reaction that applies a force to the projectile 204, thereby accelerating the projectile 204 through the launch tube 418. The projectile 204 may penetrate the end cap 202, pass through an opening in the drill bit 102, and contact the geological material. The drill bit 102 may then be operated to drill through the geological material contacted by the projectile 204.

Water, drilling fluid, or other fluid may be provided into the second annulus 122 (2). The provided fluid may exit the conduit string through one or more ports, nozzles, or other types of openings at or near the drill bit 102 and may contact the drill bit 102 to cool and lubricate the drill bit 102. Fluid may then be circulated from the bottom of the wellbore toward the surface via the third annulus 122 (3).

Interactions between the projectile 204 and the end cap 202, between the projectile 204 and the geological material, and between the drill bit 102 and the geological material may create debris, such as drill cuttings, broken rock, drilled earth, fragments of the projectile or end cap, and the like. In some implementations, by providing air or another gas through the conduit interior 126, this debris can be diverted from the bottom of the wellbore and toward the surface, such as through the third annulus 122 (3). After the projectile 204 has been accelerated and has penetrated the end cap 202, air or other gas may pass through the open end of the firing tube 418 and transfer debris from the bottom of the wellbore. The diverted debris may be carried toward the surface through the third annulus 122 (3). In some implementations, a portion of the debris may be circulated toward the surface through the first annulus 122 (1).

In addition to or instead of using gas to transfer the debris, fluid provided into the wellbore through the second annulus 122 (2) may transfer the debris. For example, some debris may have a weight, density, or other characteristic that limits the use of air to move the debris. In this case, the use of water, drilling mud or other fluid may more effectively displace debris. The debris diverted by the fluid provided through the second annulus 122 (2) may be circulated in the third annulus 122 (3) towards the surface.

Thus, the first annulus 122 (1) may serve as a vent passage that may be used to remove gas from the launch tube 418 and breech tube 416 in addition to or instead of a pump, such as the pump shown in fig. 9A and 9B. Although fig. 10 depicts an embodiment in which the first annulus 122 (1) is used to remove gas from the launch tube 418 and breech tube 416, in other implementations, either of the annuli 122 may be used. For example, the first annulus 122 (1) may be connected to atmospheric pressure at the wellbore surface through the swivel 106.

When the end cap 202 is moved into the firing tube 418 using pressurized air or another gas, the sealing bond provided by the end cap 202 provides gas into the breech tube 416 and the firing tube 418 may cause the breech tube 416 and the firing tube 418 to have a pressure that is greater than the fluid pressure near the drill bit 102 and greater than the optimal pressure for accelerating the projectile 204. The damper 206 valve upstream of the breech pipe 416 may be closed and the pressure within the breech pipe 416 and the launch tube 418 may then be released into the adjacent annulus 122 (1) by opening the valve 208 (6). For example, the valve 208 (6) may comprise a three-wave ball valve with one port connected to the swivel 106, another port connected to the gas passage 504, and another port open to the atmosphere outside of the conduit 104 (1). When the valve 208 is used to send gas to the external atmosphere, the pressure in the firing tube 418 and breech tube 416 may be reduced to about atmospheric pressure, creating an environment within the breech tube 416 and the firing tube 418 that is conducive to accelerating the projectile 204.

Fig. 11A is a diagram 1100 depicting a side cross-sectional view of an implementation of an end cap retaining mechanism 420 for retaining an end cap 202 within a catheter 104 (1). The end cap retaining mechanism 420 may be used to limit movement of the end cap 202 within the emitter tube 418 by using: the one or more keys 1102 may alternatively be other members that are capable of moving from a first position protruding into the interior of the launch tube 418 to prevent passage of the end cap 202 to a second position that does not protrude into the launch tube 418 or that may protrude less than in the first position. For example, the end cap retaining mechanism 420 may be positioned near the distal end of the emitter tube 418. As the end cap 202 is moved through the emitter tube 418 using an air flow, the pressure upstream of the end cap 202 may exceed the pressure downstream of the end cap 202. The end cap retaining mechanism 420 may prevent the end cap 202 from moving out of the distal end of the launch tube 418 by using keys 1102 that may protrude from one or more of the launch tubes 418 toward the radial guide bore 1104. After the end cap 202 has been positioned within the firing tube 418, the key 1102 may be withdrawn from the first position, such as by translating radially to a second position in which the interior of the firing tube 418 is not occluded or less occluded than when in the first position. The key 1102 may extend inwardly through a slot 1106 in the cam piston 1108.

Fig. 11B is a series of diagrams 1110 depicting an exploded view and a diagrammatic side cross-sectional view of the end cap retention mechanism 420 of fig. 11A. The cam piston 1108 may have an angled cam surface 1112 that mates with an angled key surface 1114 extending from the key 1102. The key 1102 may be biased inwardly by a garter spring 1116 or other type of biasing member.

As the cam piston 1108 moves upward, the key 1102 is pushed outward toward the second position. The cam piston 1108 may have an annular configuration with seals 1118 on the inner and outer diameters. Seal 1118, in combination with the body of cam piston 1108, may form a piston cavity 1120, and piston cavity 1120 may be connected to firing tube 418 through inlet port 914. In some implementations, if the pump shown in fig. 9 is used, piston cavity 1120 may also be connected to a fluid end 906 of the pump. The cam piston 1108 may be biased downward using a coil spring 1122 or another type of biasing member.

In operation, after projectile 204 has been launched into launch tube 418, wellbore fluids, debris, etc. may enter launch tube 418, thereby equalizing the pressure in launch tube 418 and breech tube 416 and piston chamber 1120 with the wellbore environment. For example, inlet port 914 in firing tube 418 may be connected to cam piston cavity 1120, so that the pressure on both sides of cam piston 1108 may be the same. In this case, the net hydraulic force on the cam piston 1108 may be near zero. Thus, the primary force applied to the cam piston 1108 may be a biasing force from the coil spring 1122 that may urge the cam piston 1108 downward. When the cam piston 1108 is in the downward position, the key 1102 may be moved toward the interior of the firing tube 418 by the biasing force of a garter spring 1116 or other type of biasing member.

Valve 208 (7) may be opened to allow gas to enter breech pipe 416 and firing pipe 418, or alternatively valve 208 (8) may be opened to allow drilling fluid to flow into breech pipe 416 and firing pipe 418. The gas or fluid may flush debris or wellbore fluid from within breech pipe 416 and launch pipe 418. The subsequent end cap 202 may then be released into the breech tube 416, such as by opening the air gate valve 208 (5). The gas flowing through the gas gate valve 208 (5) may move the end cap 202 until the end cap 202 seats against the shoulder provided by the extension key 1102. In some implementations, a sensor may be used to determine that end cap 202 has contacted key 1102 or reached a selected position. For example, a pressure sensor may be used to sense pressure increases that may occur after end cap 202 isolates firing tube 418 from the wellbore environment. For example, the mounting end cap 202 may form a sealed cavity including a breech tube 416, a firing tube 418, and a piston cavity 1120.

When the pressure in the breech pipe 416 and the launch tube 418 is reduced, such as by operation of a pump as shown in fig. 9 or by venting gas into the annulus 122 (1) using one or more valves 208 (6), the cam piston 1108 may travel upward, thereby providing a force to the key 1102 to drive the key outward from the interior of the launch tube 418. In this case, the pressure below the end cap 202 may be greater than the pressure above the end cap, thereby providing an upward force to the end cap 202. The end cap 202 may include one or more barbed ridges on its outer diameter or another type of feature of complementary or similar shape that may be expanded into a groove in the barrel 418. The end cap 202 may include an O-ring or other type of sealing member on its outer diameter that may create a seal within the bore of the firing tube 418, thereby enabling a low pressure (e.g., at least partially evacuated) environment to be created in the firing tube 418 and breech tube 416 upstream of the end cap 202.

After the key 1102 is moved outward from the end cap 202, acceleration of the projectile 204 through the launch tube 418 may provide a force to the end cap 202 to remove the end cap 202 from the end of the launch tube 418. In some cases, the projectile 204 may penetrate, fracture, or otherwise degrade the end cap 202. In other implementations, the gas provided into the breech tube 416 or the launch tube 418 may transfer the end cap 202 prior to contact with the projectile 204. For example, a gas having sufficient pressure may cause the end cap 202 to be dislodged from the end of the launch tube 418 into the wellbore environment. The gas may then exit the end of the emitter tube 418 to occupy the wellbore area proximate the end of the emitter tube 418. For example, if the wellbore is filled with water or another fluid, the presence of gas near the end of the launch tube 418 may displace the fluid, thereby creating a balloon through which the accelerated projectile 204 may pass to interact with the geological material in front of the launch tube 418. In other implementations, other mechanisms, such as valve 208, conduit 104, etc., oriented to deliver gas to the end of the emitter tube 418 may be used in conjunction with the removal of the end cap 202 or independent of the removal of the end cap 202 to provide gas to the wellbore region ahead of the end of the emitter tube 418. Transferring water or other fluid from the area in front of the launch tube 418 may reduce the resistance to movement of the projectile 202 that may be caused by the water or other fluid. Additionally, when water or other fluid returns to the area in front of the launch tube 418, this force caused by the movement of the fluid may further break up, degrade, or displace the geologic material or debris.

In some implementations, the end cap 202 may include barbed 1120 regions that may secure the end cap 202 at corresponding standoffs 1122 within the launch tube 418. For example, fig. 11C is a series of diagrams 1124 depicting perspective and cross-sectional views of an implementation of end cap 202. As shown in fig. 11C, the barb 1120 area may include one or more longitudinal slits 1126 in the end cap 202, forming individual fingers 1128. The spacing between the fingers 1128 due to the slits 1126 may enable the fingers 1128 to be radially compressed (e.g., deflected) as the end cap 202 moves through the emitter tube 418. For example, the emitter tube 418 may have an inner diameter that is smaller than the outer diameter of the barb 1120 area of the end cap 202. Fingers 1128 of the barb 1120 area may be deflected by contact with the inner diameter of the emitter tube 418 so that the end cap 202 can pass through the emitter tube 418 toward the mount 1122. When end cap 202 reaches mount 1122, which may be larger in diameter than the inner diameter of emitter tube 418, fingers 1128 of barb 1120 areas may be biased outward to hold end cap 202 in place at mount 1122.

In some implementations, the end cap 202 may further include a plurality of sealing members 1130 that may form a seal against the inner diameter of the emitter tube 418 to prevent the passage of air or other fluid around the end cap 202 as the end cap 202 passes through the emitter tube 418. The first sealing member 1130 (1) may be positioned along the body of the end cap 202 at a distance from the second sealing member 1130 (2). The spacing of the sealing members 1130 may be such that the portion of the end cap 202 between the first sealing member 1130 (1) and the second sealing member 1130 (2) can span the mount 1122, a port or valve, or another feature within the emitter tube 418. For example, as first sealing member 1130 (1) passes over mount 1122 during movement of end cap 202 through emitter tube 418, second sealing member 1130 (2) may remain in contact with the inner diameter of emitter tube 418 to prevent fluid from moving past end cap 202. Before second sealing member 1130 (2) reaches the position of mount 1122, first sealing member 1130 (1) may pass the position of mount 1122 and contact inner diameter 1122 of emitter tube 418 located downhole of mount 1122, thereby forming a seal. Thus, as the end cap 202 moves past features within the emitter tube 418, the at least one sealing member 1130 remains in contact with the inner diameter of the emitter tube 418, thereby preventing fluid from moving past the end cap 202.

Fig. 12A-12C are a series of diagrams 1200 depicting implementations of projectiles 204 that may be used to interact with geological materials. In some implementations, the projectile 204 (1) may include a projectile body 1202 that primarily encloses a dense material 1204. Exemplary dense materials 1204 may include granite, composite materials such as barite, or metal particles such as hematite or iron-cratobalite. In some implementations, the dense material 1204 may include metal powders bonded by cements or organic or inorganic adhesives or by sintering processes. In some cases, the projectile body 1202 may include different materials, such as frangible or degradable materials. In other implementations, the projectile body 1202 may include a dense material 1204. A sealing member 1206 associated with the projectile body 1202 may provide sealing engagement between the projectile 204 and the inside diameter of the breech tube 416 or the launch tube 418. The sealing member 1206 may hold the projectile 204 in a selected position until the pressure of the propellant material from behind the projectile 204 is sufficient to overcome the sealing force, thereby accelerating the projectile 204 through the launch tube 418.

While the previously discussed implementations describe the provision of gas, propellant material, and liquid into the breech tube 416 or the launch tube 418, such as through the use of one or more conduits 104, in other implementations, one or more of these components may be included within the projectile 204.

For example, fig. 12A depicts a projectile 204 (2) including a propellant material 1208 integrated within a projectile body 1202. For example, when the projectile body 1202 breaks or degrades in response to pressure, temperature, impact, or other conditions, the propellant material 1208 within the projectile body 1202 may provide a force to the projectile 204 to accelerate the projectile 204 through the launch tube 418. The spacer 1210 may separate the dense material 1204 from the integrated propellant material 1208 within the projectile 204.

In another implementation shown in fig. 12A, the projectile 204 (3) may include an explosive material 1212 integrated within the projectile body 1202. The spacer 1210 may separate the explosive material 1212 from the dense material 1204. In one implementation, the integrated explosive material 1212 may include ammonium nitrate fuel oil (AND) that has a high impact detonation threshold AND is unlikely to detonate during normal handling, transport, or transportation downhole, but rather may detonate in response to high impact pressures generated by the impact between the projectile 204 AND the geological material. For example, an impact velocity of 700m/s or greater may cause the explosive material 1212 to detonate after impact. In some implementations, the explosive material 1212 may include shaped charges so that energy from an explosion can be directed in a preferred orientation to maximize hard rock broken by the explosion. For example, a projectile 204 including a detonatable or explosive material 1212 may create a larger region of damaged geological material than a projectile 204 without an explosive material 1212. In some implementations, the body or shell of the projectile 204 may be formed of a dense material 1204 to protect the explosive material 1212 from detonating until an impact sufficient to fracture the body or shell of the projectile 204 occurs.

In some implementations, the type of projectile 204 used to extend the wellbore may vary. For example, the projectile 204 including the explosive material 1212 may be accelerated in an alternating fashion with the projectile 204 that includes primarily the dense material 1204 and is free of the explosive material 1212. As another example, two projectiles 204 without explosive material 1212 may accelerate after each projectile 204 that includes explosive material 1212. The order of the projectiles 204 being accelerated may be selected based on the characteristics of the geologic material (such as composition or hardness), wellbore conditions (such as depth or pressure, etc.).

Fig. 12B depicts side and end cross-sectional views of an implementation of a projectile 204 having a tapered front portion 1214. In some cases, the projectile 204 shown in fig. 12B may be accelerated using a ram effect between features of the projectile 204 and features of the launch tube 418, such that the launch tube 418 can act as a ram accelerator. The projectile 204 may have a truncated or flat back 1216. Projectile 204 may include an inner rod penetrator 1218, which may be formed of steel or other dense material 1204 (such as ceramic, plastic, etc.). In some implementations, rod penetrator 1218 may include copper, depleted uranium, etc. Projectile 204 may include an inner material 1220 within the body and an outer material 1222, such as a dense shell. In some implementations, the inner material 1220 may include a solid plastic material or other material entrained within the wellbore, such as explosives, hole cleaners, anti-leak materials, water, or ice. In some implementations, a plastic explosive or a special explosive may be embedded in rod penetrator 1218. When projectile 204 interacts with the geological material, explosive material 1212 may be entrained into the wellbore where it may be detonated. In another embodiment, the outer material 1222 may include a housing or body connected to a lanyard system configured to pull individual explosives into the wellbore. In some implementations, at least a portion of the projectile 204 may include a material that is combustible during conditions present during acceleration of the projectile 204. For example, the outer material 1222 may include aluminum. In some implementations, the projectile 204 may omit the on-board propellant material.

In some implementations, the back 1216 of the projectile 204 may include an obturator to prevent air or propellant material from escaping as the projectile 204 accelerates through the launch tube 418. The obturator may be an integral part of the projectile 204 or a separate and removable unit.

Projectile 204 may also include one or more fins 1224, rails, or other guiding features. For example, the projectile 204 may be rifled to induce a helix. Fins 1224 may be positioned toward front 1214, back 1216, or both of projectile 204 to provide guidance during acceleration. In some implementations, the body of the projectile 204 may extend outward to form fins or other guiding features. In some implementations, fins 1224 may be coated with an abrasive material that aids in cleaning launch tube 418 as projectile 204 moves therein. For example, one or more of fins 1224 may include grinding tips 1226.

In some implementations, the projectile 204 may incorporate one or more sensors or other instruments. The sensor may include an accelerometer, a temperature sensor, a gyroscope, and the like. Information from these sensors may be returned to the receiving device using radio frequency, optical transmission, acoustic transmission, etc. This information may be used to modify one or more ignition parameters, characterize the material in the wellbore, and the like.

Fig. 12C depicts side and end cross-sectional views of an implementation of a projectile 204 having a tapered front portion 1214 and a rectangular cross-sectional shape. A rod penetrator 1218 extends between the front 1214 and back 1216 of the projectile 204. Although penetrator 1218 is depicted as a rod, in other implementations, the penetrator may have one or more other shapes, such as a prismatic solid.

Projectile 204 may include an intermediate core 1228 and an outer core 1230 proximate penetrator 1218. In some implementations, one or both of the intermediate core 1228 or the other core 1230 may be omitted. As described above, the projectile 204 may include a body having an inner material 1220 surrounding a core and an outer material 1222 surrounding the inner material 1220.

In some implementations, the projectile 204 may include a pyrotechnic igniter 1232. The pyrotechnic igniter 1232 may be configured to initiate, sustain, or otherwise support combustion of the propellant material to accelerate the projectile 204.

As shown in fig. 12C, in some implementations, the projectile 204 may not have a radially symmetric shape. For example, the shape of the projectile 204 may be configured to provide guidance or direction to the projectile 204. Continuing with the example, projectile 204 may have a wedge or chisel shape. As described with respect to fig. 12B, projectile 204 may also include one or more fins 1224, rails, or other guiding features.

In some implementations, the projectile 204 may include one or more abrasive materials. The abrasive material may be disposed within the projectile 204 or on the projectile 204 and may provide an abrasive action after impact with the geological material 106. The abrasive material may include materials such as diamond, garnet, silicon carbide, tungsten, copper, and the like. For example, the intermediate core 1228 may include an abrasive material that may be layered between the penetrator 1218 and the outer core 1230.

FIG. 13 is a diagram 1300 depicting an implementation of a system that may include a source of propellant material that may be located downhole within the system. While the previous implementations include the use of one or more conduits 104 to transport the propellant material, in other implementations the propellant material may be delivered through a conduit 104 (1) in a canister or other container whose volume includes sufficient material to accelerate the projectile 204. In the implementation shown in fig. 13, the propellant material stored in a system for retaining compressed liquid fuel or other propellant material, such as propellant container 1302, may be intermittently re-supplied. For example, the propellant container 1302 may be stored proximate to the BHA 114 or in association with the BHA 114. Continuing with the example, a compressed liquid fuel, such as propane, butane, or other type of propellant material, may be provided into propellant container 1302 along conduit 104 (1). Propellant container 1302 may include an upper valve 208 (9) and a lower valve 208 (10) to form a propellant lock aligned with conduit 104 (1). The additional valve 208 (11) may be connected to a bypass passage, such as a propellant line 1304 (1), which may be connected to an annular fuel tank 1306 downstream of the propellant container 1302.

To fuel the system, the lower valve 208 (10) may be closed and a propellant container 1302 may be provided into the conduit 104 (1) to rest on the lower valve 208 (10) or another structural member that may extend into the interior of the conduit 104 (1). The upper valve 208 (9) may then be closed to form a propellant lock around the propellant container 1302, and the propellant container 1302 may be pierced or otherwise opened by a mechanism to enable propellant material to flow into the fuel tank 1306 via the propellant line 1304 (1). After propellant material has flowed from the propellant container 1302 into the fuel tank 1306, the lower valve 208 (11) may be opened and the propellant container 1302 may be allowed to pass through the conduit 104 (1) to the bottom of the wellbore. Propellant container 1302 may be formed of a material that is breakable by projectile 204 or drill bit 102.

The propellant container 1302 may carry sufficient propellant material to accelerate a plurality of projectiles 204, such as one hundred projectiles 204 or more. As the end cap 202 and projectile 204 pass through the conduit 104 (1), the valve 208 on either side of the portion receiving the propellant container 1302 may be opened and the propellant lock may be used as an additional portion of the conduit 104 (1). The projectile 204 may be accelerated by providing propellant material from the fuel tank 1306 to the breech pipe 416 via a propellant line 1304 (2) controlled by valve 208 (8). Air or another gas may be provided into the breech tube 416 at or near the time of providing the propellant material to promote mixing of the gas with the propellant material. Where the propellant material comprises compressed liquid fuel, the lower downstream pressure may enable the compressed liquid fuel to decompress and gasify as it enters the breech tube 416.

While the implementations described herein use projectile impacts and drill bits 102 to extend the wellbore, other implementations may include the use of projectiles 204 without the use of drill bits 102. For example, successive projectile impacts may pulverize rock and other geologic materials, while a liquid or gas may be used to remove debris from the bottom of the wellbore. In other implementations, impact-based drilling techniques, such as pile drivers, may be used. For example, an axial or rotary hammer may be used to form the wellbore, thereby reducing or eliminating the use of conventional downhole rotational energy and the need for a large rig for delivering torque and weight to the drill bit 102.

Although certain steps have been described as being performed by certain devices, processes, or entities, this is not required and a person of ordinary skill in the art will understand a variety of alternative implementations.

In addition, one of ordinary skill in the art will readily recognize that the techniques described above may be utilized in a variety of devices, environments, and situations. Although the present disclosure has been written with respect to specific embodiments and implementations, various changes and modifications may be suggested to one skilled in the art and it is intended that the present disclosure encompass such changes and modifications as fall within the scope of the appended claims.

Some implementations useful herein are described below with respect to the following clauses:

(clause 1) a system, comprising: a first conduit having a first end oriented toward the geological material, and a second end; a gas source connected to the second end of the first conduit; a second conduit positioned around the first conduit, wherein the first annulus is located between the first conduit and the second conduit; a first valve movable to separate the interior of the first conduit from the first annulus to enable gas flow from the interior to the first annulus; a first end cap positionable between the interior and the geological material, wherein the first end cap is configured to separate the interior from an environment external to the first conduit; and a first projectile positionable within the interior, wherein the first projectile is configured to accelerate toward the first end to contact a portion of the geological material.

(clause 2) the system of clause 1, further comprising: a drill bit positioned at a first end of the first conduit, wherein the drill bit is oriented to contact the geological material; a third conduit positioned around the second conduit, wherein the second annulus is located between the second conduit and the third conduit; and a fluid source connected with the third conduit, wherein the fluid source is configured to provide fluid into the second annulus to contact the drill bit and transfer debris formed by interactions between the geological material and one or more of the first projectile or the drill bit.

(clause 3) the system of clause 1 or clause 2, further comprising: a second valve located between the first projectile and the gas source; wherein gas from the gas source provided into the interior of the first conduit positions the first end cap between the interior and the geological material and positions the first projectile within the interior; and wherein the second valve is closed and the first valve is opened to at least partially evacuate gas from the interior into the first annulus.

(clause 4) the system of any of clauses 1-3, wherein: one or more of a first projectile or gas within the first conduit first transfers the first endcap, after which the first projectile contacts a portion of the geological material, and wherein transferring the first endcap places the interior of the first conduit in communication with the environment exterior to the first conduit; interactions between the first projectile and portions of the geological material form debris; and gas from the gas source provided through the interior of the first conduit toward the first end transfers debris into the second annulus outside of the second conduit.

(clause 5) the system of any of clauses 1-4, further comprising: a first member movable between a first position extending at least partially into the interior of the first conduit and a second position; wherein the first end cap is positioned between the interior and the geological material by contacting the first end cap with the first member in the first position; and wherein the first member is moved to the second position after the first end cap contacts the first member.

(clause 6) the system of any of clauses 1-5, further comprising: a third conduit positioned within the first annulus, wherein the third conduit includes a third end connected to the interior of the first conduit, and a fourth end; and a source of propellant material connected to the fourth end, wherein the source of propellant material is configured to provide propellant material into the interior of the first conduit through the third conduit to apply a force to the first projectile to accelerate the first projectile toward the first end.

(clause 7) the system of any of clauses 1-6, further comprising: a container connected to the second end of the first conduit, wherein the first end cap, the first projectile, the second end cap, and the second projectile are located within the container; and wherein the first end cap, the first projectile, the second end cap and the second projectile are arranged such that the first end cap is provided into the interior of the first conduit before the first projectile, the first projectile is provided into the interior before the second end cap, and the second end cap is provided into the interior before the second projectile.

(clause 8) a system, comprising: a first conduit having a first end oriented toward the geological material, and a second end; a first member positioned between the first portion of the first conduit and the second portion of the first conduit, wherein the first member is movable between a first position at least partially occluding an interior of the first conduit and a second position; a second member positioned between the first member and the second portion of the first conduit, wherein the second member is movable between a third position at least partially occluding an interior of the first conduit and a fourth position; a first end cap positionable within the interior of the first conduit, wherein the first end cap is movable from the first portion to the second portion of the first conduit by moving the first end cap past the first member when the second member is in the third position, and by moving the first end cap past the second member in the fourth position when the first member is in the first position; and a first projectile positionable within the interior, wherein the first projectile is movable from the first portion to the second portion of the first conduit by moving the first projectile past the first member when the second member is in the third position and by moving the first projectile past the second member in the fourth position when the first member is in the first position.

(clause 9) the system of clause 8, wherein: the second member in the third position prevents the first end cap from moving toward the second portion when the first member is in the second position; and when the second member is in the fourth position, the first member in the first position prevents the first projectile from moving toward the second portion.

(clause 10) the system of clause 8 or clause 9, further comprising: a gas source in communication with the first conduit, wherein one or more of: the first member includes a first valve configured to at least partially block gas from traveling from the gas source to the second portion when the first member is in the first position; or the second member includes a second valve configured to at least partially block gas from traveling from the gas source to the second portion when the second member is in the third position.

(clause 11) the system of any of clauses 8 or 9, wherein one or more of the following: the first member extending from the inner diameter of the first conduit into the interior when in the first position; or the second member extends from the inner diameter of the first conduit into the interior when in the third position.

(clause 12) the system of clause 11, further comprising: a gas source in communication with the first conduit; and one or more valves positioned between the second member and the first end of the first conduit, wherein the one or more valves are movable to block gas from traveling from the gas source toward the second portion of the first conduit.

(clause 13) the system of any of clauses 8-12, wherein one or more of the following: the first member moving toward the second position causes the second member to move toward the third position; or movement of the second member toward the fourth position causes movement of the first member toward the first position.

(clause 14) the system of any of clauses 8-13, further comprising: a gas source in communication with the first conduit; one or more first valves positioned between the first portion of the first conduit and the second portion of the first conduit, wherein the one or more first valves are movable to block gas from traveling from the gas source to the second portion of the first conduit; a channel extending through a wall of the first conduit, wherein the channel is separate from the interior and extends from a first side of the one or more first valves to a second side of the one or more first valves and connects the first portion to the second portion; and a second valve in the channel, wherein the second valve is movable to block movement of gas through the channel.

(clause 15) the system of any of clauses 8-14, further comprising: a gas source in communication with the first conduit; one or more first valves positioned between the first portion of the first conduit and the second portion of the first conduit, wherein the one or more first valves are movable to block gas from traveling from the gas source to the second portion of the first conduit; and an annular pump engaged with the second portion of the first conduit, wherein the annular pump removes gas from the second portion of the first conduit when at least one of the one or more first valves prevents gas from entering the second portion of the first conduit.

(clause 16) the system of any of clauses 8-14, further comprising: a gas source in communication with the first conduit; one or more first valves positioned between the first portion of the first conduit and the second portion of the first conduit, wherein the one or more first valves are movable to block gas from traveling from the gas source to the second portion of the first conduit; a second conduit positioned around the first conduit, wherein the first annulus is located between the first conduit and the second conduit; and a second valve separating the interior of the first conduit from the first annulus to enable gas flow from the interior to the first annulus.

The system of any of clauses 8-16, wherein the second portion of the first conduit comprises a first inner diameter and a seat having a second inner diameter greater than the first inner diameter, and wherein the first end cap comprises: a plurality of fingers at an end of the first end cap, wherein each finger of the plurality of fingers is separated from at least one other finger of the plurality of fingers by at least one slit; wherein at least one finger of the plurality of fingers is configured to deflect relative to at least one other finger of the plurality of fingers to provide a first end cap having a first outer diameter configured to move the first end cap through a second portion of a first conduit having a first inner diameter; and wherein at least one finger of the plurality of fingers is biased outwardly from the first end cap to provide an end cap having a second outer diameter that is greater than the first inner diameter, and wherein the second outer diameter is configured to retain the first end cap in a position within the seat.

The system of any of clauses 8-17, wherein the second portion of the first conduit comprises a first inner diameter and a seat having a second inner diameter greater than the first inner diameter, wherein the seat has a first length, and wherein the first end cap comprises: a first seal located at a first location on the end cap body; and a second seal located at a second location on the end cap body; wherein the distance between the first location and the second location is greater than the first length.

(clause 19) a method, comprising: moving the end cap from the first end of the first conduit toward the second end of the first conduit, wherein the second end is oriented toward the geological material, and wherein movement of the end cap toward the second end is limited by a first member within the first conduit between the first end and the second end; moving the projectile from the first end of the first conduit toward the second end, wherein movement of the projectile toward the second end is limited by the end cap; moving the first member away from the interior of the first conduit; moving the end cap past the first member, wherein movement of the end cap toward the second end is limited by a second member positioned between the first member and the second end; moving the first member inwardly, wherein movement of the projectile toward the second end is limited by the first member; moving the second member away from the interior; moving the end cap past the second member to a first position within the first conduit, wherein the end cap separates the interior of the first conduit from the environment exterior to the first conduit; moving the first member away from the interior and the second member toward the interior; moving the projectile past the first member, wherein movement of the projectile toward the second end is limited by the second member; moving the second member away from the interior; moving the projectile past the second member to a second position within the first conduit, wherein the end cap is located between the projectile and the second end; providing a propellant material into the first conduit; and accelerating the projectile toward the second end using a force applied by the propellant material, wherein the projectile contacts a portion of the geological material.

(clause 20) the method of clause 19, wherein moving the end cap and the projectile by providing gas into the first conduit, the method further comprising: after the end cap is moved to the first position, gas is removed from the interior of the first conduit into the annulus outside the first conduit.

(clause 21) the method of clause 19 or clause 20, further comprising: a gas is provided between the first end of the first conduit and the geological material, wherein the gas displaces material between the first end and the geological material, and wherein the projectile passes through the gas to contact a portion of the geological material.

(clause 22) the method of any of clauses 19-21, further comprising: contacting a portion of the geological material using a drill bit positioned at a second end of the first conduit, wherein interactions between the geological material and one or more of the projectile or the drill bit produce debris; and providing a fluid into a first annulus between the first conduit and a second conduit positioned around the first conduit, wherein the fluid contacts the drill bit and transfers debris into a second annulus external to the second conduit.

Claims

1. A system, the system comprising:

a first conduit having a first end and a second end, the first end oriented toward the geological material;

A gas source connected to the second end of the first conduit;

a second conduit positioned around the first conduit, wherein a first annulus is located between the first conduit and the second conduit;

a first valve movable to separate an interior of the first conduit from the first annulus to enable gas flow from the interior to the first annulus;

a first end cap positionable between the interior and the geological material, wherein the first end cap is configured to separate the interior from an environment external to the first conduit; and

a first projectile positionable within the interior, wherein the first projectile is configured to accelerate toward the first end to contact a portion of the geological material.

2. The system of claim 1, the system further comprising:

a drill bit positioned at the first end of the first conduit, wherein the drill bit is oriented to contact the geological material;

a third conduit positioned around the second conduit, wherein a second annulus is located between the second conduit and the third conduit; and

A fluid source connected with the third conduit, wherein the fluid source is configured to provide fluid into the second annulus to contact the drill bit and transfer debris formed by interaction between the geological material and one or more of the first projectile or the drill bit.

3. The system of claim 1 or claim 2, the system further comprising:

a second valve located between the first projectile and the gas source;

wherein the gas from the gas source provided into the interior of the first conduit positions the first end cap between the interior and the geological material and positions the first projectile within the interior; and is also provided with

Wherein the second valve is closed and the first valve is opened to at least partially evacuate the gas from the interior into the first annulus.

4. A system according to any one of claims 1-3, wherein:

transferring the first end cap prior to the first projectile contacting the portion of the geological material, and wherein transferring the first end cap places the interior of the first conduit in communication with the environment exterior to the first conduit;

Interactions between the first projectile and the portion of the geological material form debris; and is also provided with

The gas from the gas source provided through the interior of the first conduit toward the first end transfers the debris into a second annulus external to the second conduit.

5. The system of any one of claims 1-4, further comprising:

a first member movable between a first position extending at least partially into the interior of the first conduit and a second position;

wherein the first end cap is positioned between the interior and the geological material by contacting the first end cap with the first member in the first position; and is also provided with

Wherein the first member is moved to the second position after the first end cap is in contact with the first member.

6. The system of any one of claims 1-5, further comprising:

a fourth conduit positioned within the first annulus, wherein the fourth conduit includes a third end and a fourth end, the third end being connected to the interior of the first conduit; and

A source of propellant material connected to the fourth end, wherein the source of propellant material is configured to provide propellant material into the interior of the first conduit through the fourth conduit to apply a force to the first projectile to accelerate the first projectile toward the first end.

7. A system, the system comprising:

a first member positioned between a first portion of the first conduit and a second portion of the first conduit, wherein the first member is movable between a first position at least partially occluding an interior of the first conduit and a second position;

a second member positioned between the first member and the second portion of the first conduit, wherein the second member is movable between a third position at least partially occluding the interior of the first conduit and a fourth position;

a first end cap positionable within the interior of the first conduit, wherein the first end cap is movable from the first portion to the second portion of the first conduit by moving the first end cap past the first member when the second member is in the third position, and by moving the first end cap past the second member in the fourth position when the first member is in the first position; and

A first projectile positionable within the interior, wherein the first projectile is movable from the first portion to the second portion of the first conduit by moving the first projectile past the first member when the second member is in the third position and by moving the first projectile past the second member in the fourth position when the first member is in the first position.

8. The system of claim 7, wherein one or more of:

the first member extending from an inner diameter of the first conduit into the interior when in the first position to inhibit movement of one or more of the first end cap or the first projectile; or alternatively

The second member extends from the inner diameter of the first conduit into the interior when in the third position to inhibit movement of one or more of the first end cap or the first projectile.

9. The system of claim 7 or 8, the system further comprising:

a gas source in communication with the first conduit; and

one or more first valves positioned between the second member and the first end of the first conduit, wherein the one or more first valves are movable to block gas from traveling from the gas source toward the second portion of the first conduit.

10. The system of any one of claims 7-9, wherein one or more of:

movement of the first member toward the second position causes movement of the second member toward the third position; or alternatively

Movement of the second member toward the fourth position causes movement of the first member toward the first position.

11. The system of any of claims 7-10, the system further comprising:

a gas source in communication with the first conduit;

one or more second valves positioned between the first portion of the first conduit and the second portion of the first conduit, wherein the one or more second valves are movable to block gas from traveling from the gas source toward the second portion of the first conduit;

a channel extending through a wall of the first conduit, wherein the channel is separate from the interior and extends from a first side of the one or more second valves to a second side of the one or more second valves and connects the first portion to the second portion; and

a third valve in the passage, wherein the third valve is movable to prevent movement of the gas through the passage.

12. The system of any of claims 7-11, the system further comprising:

a second conduit positioned around the first conduit, wherein a first annulus is located between the first conduit and the second conduit; and

a second valve separating the interior of the first conduit from the first annulus to enable gas flow from the interior to the first annulus.

13. The system of any of claims 7-12, wherein the second portion of the first conduit comprises a first inner diameter and a seat having a second inner diameter greater than the first inner diameter, and wherein the first end cap comprises:

a plurality of fingers located at an end of the first end cap, wherein each finger of the plurality of fingers is separated from at least one other finger of the plurality of fingers by at least one slit;

a first sealing member located at a first location on the body of the first end cap; and

a second sealing member located at a second location on the body of the first end cap;

wherein at least one finger of the plurality of fingers is configured to deflect relative to at least one other finger of the plurality of fingers to provide the first end cap with a first outer diameter configured to move the first end cap through the second portion of the first conduit with the first inner diameter;

Wherein the at least one finger of the plurality of fingers is biased outwardly from the first end cap to provide the first end cap with a second outer diameter that is greater than the first inner diameter, and wherein the second outer diameter is configured to retain the first end cap in a position within the seat; and is also provided with

Wherein the distance between the first location and the second location is greater than a first length.

14. A method, the method comprising:

moving an end cap from a first end of a first conduit toward a second end of the first conduit, wherein the second end is oriented toward a geological material, and wherein movement of the end cap toward the second end is limited by a first member within the first conduit between the first end and the second end;

moving a projectile from the first end of the first conduit toward the second end, wherein movement of the projectile toward the second end is limited by the end cap;

moving the first member away from the interior of the first conduit;

moving the end cap past the first member, wherein movement of the end cap toward the second end is limited by a second member located between the first member and the second end;

Moving the first member toward the interior, wherein movement of the projectile toward the second end is limited by the first member;

moving the second member away from the interior;

moving the end cap to a first position within the first conduit through the second member, wherein the end cap separates the interior of the first conduit from an environment external to the first conduit;

moving the first member away from the interior and the second member toward the interior;

moving the projectile past the first member, wherein movement of the projectile toward the second end is limited by the second member;

moving the second member away from the interior;

moving the projectile through the second member to a second position within the first conduit, wherein the end cap is located between the projectile and the second end;

providing a propellant material into the first conduit; and

accelerating the projectile toward the second end using a force applied by the propellant material, wherein the projectile contacts a portion of the geological material.

15. The method of claim 14, the method further comprising:

Providing a gas between the first end of the first conduit and the geological material, wherein the gas displaces material between the first end and the geological material, and wherein the projectile passes through the gas to contact the portion of the geological material.