AN IMPACT TRANSMISSION MECHANISM FOR A ROTARY PERCUSSION DRILLING TOOL

Abstract

A tubular apparatus includes an upper joint, an inner cylinder, a piston, a metal seal, a bearing, and an anvil. The upper joint is connected to an outer cylinder. The inner cylinder has a cavity and is disposed within the outer cylinder. The piston has a piston rod disposed within the cavity of the inner cylinder and is moveable along an axis. The metal seal is disposed between the inner cylinder and a cylinder gland. The piston rod extends through the cylinder gland to a hammer, and a portion of the hammer is disposed within an outer tube. The bearing is disposed between the hammer and the outer tube. The anvil has a bit head and is connected to the hammer.

Description

BACKGROUND

In the oil and gas industry, hydrocarbons are located in porous formations far beneath the Earth's surface. Wells are drilled into the formation to produce the hydrocarbons. A well is made of a wellbore drilled into the Earth's surface. The wellbore is supported by one or more casing strings, and cement is pumped between each casing string and the wellbore. The cement provides a fluid barrier and structural support to the casing string in the wellbore. The wellbore is drilled using a drill bit. There are various types of drill bits used for different applications. One type of drill bit for use in hard formation applications is a hammer drill bit. A hammer drill bit uses a high impact force to aid in breaking down the rock to build the wellbore.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

This disclosure presents, in accordance with one or more embodiments, methods and tubular apparatuses for a wellbore. The tubular apparatus includes an upper joint, an inner cylinder, a piston, a metal seal, a bearing, and an anvil. The upper joint is connected to an outer cylinder. The inner cylinder has a cavity and is disposed within the outer cylinder. The piston has a piston rod, is disposed within the cavity of the inner cylinder, and is moveable along an axis. The metal seal is disposed between the inner cylinder and a cylinder gland. The piston rod extends through the cylinder gland to a hammer, and a portion of the hammer is disposed within an outer tube. The bearing is disposed between the hammer and the outer tube. The anvil has a bit head and is connected to the hammer.

The method includes providing a tubular apparatus having an upper joint, an inner cylinder, a piston, a metal seal, a bearing, and an anvil. The tubular apparatus is run into the wellbore. The tubular apparatus is actuated to hammer the bit head against a bottom of the wellbore. The bottom of the wellbore is broken down to extend the wellbore.

Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency. The sizes and relative positions of elements in the drawings are not necessarily drawn to scale. For example, the shapes of various elements and angles are not necessarily drawn to scale, and some of these elements may be arbitrarily enlarged and positioned to improve drawing legibility. Further, the particular shapes of the elements as drawn are not necessarily intended to convey any information regarding the actual shape of the particular elements and have been solely selected for ease of recognition in the drawing.

FIG. 1 shows an exemplary well site in accordance with one or more embodiments.

FIG. 2 shows a tubular apparatus in accordance with one or more embodiments.

FIG. 3 shows an element gland in accordance with one or more embodiments.

FIGS. 4a-4d show an inner cylinder in accordance with one or more embodiments.

FIG. 5 shows an anvil in accordance with one or more embodiments.

FIGS. 6a and 6b show a bearing in accordance with one or more embodiments.

FIGS. 7a-7e show a bearing in accordance with one or more embodiments.

FIG. 8 shows a bearing in accordance with one or more embodiments.

FIG. 9 shows a flowchart in accordance with one or more embodiments.

DETAILED DESCRIPTION

In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.

FIG. 1 illustrates an exemplary well site (100). In general, well sites may be configured in a myriad of ways. Therefore, the well site (100) is not intended to be limiting with respect to the particular configuration of the drilling equipment. The well site (100) is depicted as being on land. In other examples, the well site (100) may be offshore, and drilling may be carried out with or without use of a marine riser. A drilling operation at well site (100) may include drilling a wellbore (102) into a subsurface including various formations (104, 106). For the purpose of drilling a new section of wellbore (102), a drill string (108) is suspended within the wellbore (102).

The drill string (108) may include one or more drill pipes (109) connected to form conduit and a bottom hole assembly (BHA) (110) disposed at the distal end of the conduit. The BHA (110) may include a drill bit (112) to cut into the subsurface rock. The BHA (110) may include measurement tools, such as a measurement-while-drilling (MWD) tool (114) and logging-while-drilling (LWD) tool 116. Measurement tools (114, 116) may include sensors and hardware to measure downhole drilling parameters, and these measurements may be transmitted to the surface using any suitable telemetry system known in the art. The BHA (110) and the drill string (108) may include other drilling tools known in the art but not specifically shown.

The drill string (108) may be suspended in wellbore (102) by a derrick (118). A crown block (120) may be mounted at the top of the derrick (118), and a traveling block (122) may hang down from the crown block (120) by means of a cable or drilling line (124). One end of the cable (124) may be connected to a drawworks (126), which is a reeling device that can be used to adjust the length of the cable (124) so that the traveling block (122) may move up or down the derrick (118).

The traveling block (122) may include a hook (128) on which atop drive (130) is supported. The top drive (130) is coupled to the top of the drill string (108) and is operable to rotate the drill string (108). Alternatively, the drill string (108) may be rotated by means of a rotary table (not shown) on the drilling floor (131). Drilling fluid (commonly called mud) may be stored in a mud pit (132), and at least one pump (134) may pump the mud from the mud pit (132) into the drill string (108). The mud may flow into the drill string (108) through appropriate flow paths in the top drive (130) (or a rotary swivel, if a rotary table is used instead of a top drive to rotate the drill string (108)).

In one implementation, a system (199) may be disposed at or communicate with the well site (100). System (199) may control at least a portion of a drilling operation at the well site (100) by providing controls to various components of the drilling operation. In one or more embodiments, system (199) may receive data from one or more sensors (160) arranged to measure controllable parameters of the drilling operation. As a non-limiting example, sensors (160) may be arranged to measure WOB (weight on bit), RPM (drill string rotational speed), GPM (flow rate of the mud pumps), and ROP (rate of penetration of the drilling operation).

Sensors (160) may be positioned to measure parameter(s) related to the rotation of the drill string (108), parameter(s) related to travel of the traveling block (122), which may be used to determine ROP of the drilling operation, and parameter(s) related to flow rate of the pump (134). For illustration purposes, sensors (160) are shown on drill string (108) and proximate mud pump (134). The illustrated locations of sensors (160) are not intended to be limiting, and sensors (160) could be disposed wherever drilling parameters need to be measured. Moreover, there may be many more sensors (160) than shown in FIG. 1 to measure various other parameters of the drilling operation. Each sensor (160) may be configured to measure a desired physical stimulus.

During a drilling operation at the well site (100), the drill string (108) is rotated relative to the wellbore (102), and weight is applied to the drill bit (112) to enable the drill bit (112) to break rock as the drill string (108) is rotated. In some cases, the drill bit (112) may be rotated independently with a drilling motor. In further embodiments, the drill bit (112) may be rotated using a combination of the drilling motor and the top drive (130) (or a rotary swivel if a rotary table is used instead of a top drive to rotate the drill string (108)).

While cutting rock with the drill bit (112), mud is pumped into the drill string (108). The mud flows down the drill string (108) and exits into the bottom of the wellbore (102) through nozzles in the drill bit (112). The mud in the wellbore (102) then flows back up to the surface in an annular space between the drill string (108) and the wellbore (102) with entrained cuttings. The mud with the cuttings is returned to the pit (132) to be circulated back again into the drill string (108). Typically, the cuttings are removed from the mud, and the mud is reconditioned as necessary, before pumping the mud again into the drill string (108). In one or more embodiments, the drilling operation may be controlled by the system (199).

Hammer drill bits are primarily used in hard, brittle rock formations. However, current designs of hammer drill bits are only formulated for use in shallow and low temperature operations, but there are hard and brittle rock formations located deeper within the Earth's surface. Current hammer drill bit designs are unable to be used in said formations and, thus, other types of drill bits, that are less efficient, must be used. Therefore, a hammer drill bit designed for use in a deeper and high temperature well is beneficial. As such, FIGS. 2-7 represent, in accordance with one or more embodiments, a tubular apparatus that may be used as a hammer drill bit in high temperature drilling operations.

FIG. 2 shows a partial cross section of a tubular apparatus (200). The tubular apparatus (200) may be used as the drill bit (112) in the drilling operation depicted in FIG. 1. The outer body of the tubular apparatus (200) may be made of an upper joint (202), an outer cylinder (204), a middle joint (206), an outer tube (208), an octagonal sleeve (210), and an anvil (500). That is, the aforementioned components are the components of the tubular apparatus (200) that may have at least a portion of their body disposed within an external environment, such as a wellbore (102).

The upper joint (202) may be connected to the outer cylinder (204), the outer cylinder (204) may be connected to the middle joint (206), the middle joint (206) may be connected to the outer tube (208), the outer tube (208) may be connected to the octagonal sleeve (210), and the octagonal sleeve (210) may be connected to the anvil (500). The anvil (500) may have a sliding fit with the octagonal sleeve (210). All connections may be made using any connection in the art, such as a thread-able connection. Further, all of these components may be made out of any durable material known in the art, such as steel.

A flow path (212) extends through the tubular apparatus (200) as shown in FIG. 2. A fluid may follow the flow path (212). The fluid may be any fluid known in the art, such as a drilling mud. The fluid may enter the tubular apparatus (200) through the upper joint (202). The upper joint (202) may be connected to a drill string (108), or any other deployment apparatus. In accordance with one or more embodiments, the fluid may be transported from the mud pit (132) to the upper joint (202) of the tubular apparatus (200) through the deployment apparatus.

The fluid may exit the upper joint (202) into an element gland (300). The element gland (300) is disposed within the outer cylinder (204) and adjacent to a distal portion (216) of the upper joint (202). In accordance with one or more embodiments, the element gland (300) is slotted into the outer cylinder (204), against the jet element (214), prior to the outer cylinder (204) being connected to the upper joint (202). The element gland (300) may be sealed and tightened, within the outer cylinder (204), using a rubber ring (not pictured).

The element gland (300) is depicted in further detail in FIG. 3. The element gland (300) has a cylinder-shaped element body (302) with an outer circumferential surface (304). A central hole (306) is located in the geometric center of the element gland (300) and may extend through the element body (302) of the element gland (300) from one side of the element gland (300) to the other.

A plurality of shunt holes (308) may be disposed axially around the central hole (306). In one or more embodiments, there may be two shunt holes (308) disposed around the central hole (306). The shunt holes (308) may also extend through the element body (302) of the element gland (300) from one side to the other. The central hole (306) and the shunt holes (308) may guide the fluid into a jet element (214) to move a piston (218) along an axis (220). A spiral ring groove (310) is machined into the outer circumferential surface (304). The fluid produces a throttling effect in the spiral ring groove (310) which prevents leakage and provides a sealing aspect.

The fluid may exit the shunt holes (308) and the central hole (306) into the jet element (214). The jet element (214) may be disposed directly within the outer cylinder (204) and be located between the element gland (300) and an inner cylinder (400). The jet element (214) may operate using the Coanda effect. Specifically, an inlet (not pictured) of the jet element (214) receives a continuous flow of fluid from the element gland (300). The fluid is split within the jet element (214) and exits the jet element (214) using two outlets (not pictured) into the inner cylinder (400). The jet element (214) uses the force of the fluid to reciprocate the piston (218) along the axis (220). The fluid flows out of the jet element (214) into the inner cylinder (400).

The piston (218) is disposed within a cavity (402) of the inner cylinder (400). The inner cylinder (400) is disposed within the outer cylinder (204). The inner cylinder (400) is shown in detail in FIGS. 4a-4d. FIG. 4a shows a cross section of the inner cylinder (400), a cylinder head (404), a metal ring (406), and a cylinder gland (408). FIG. 4a also shows a first cycle of the fluid path (212). FIG. 4b shows a second cycle of the fluid path (212). FIG. 4c shows the cross section of the cylinder head (404) along the axis A-A′. FIG. 4d shows a schematic diagram of the metal ring (406).

The two outlets of the jet element (214) are aligned with a first inlet (410) and a second inlet (412) of the inner cylinder (400). The fluid enters and exits the inner cylinder (400) through the first inlet (410) and the second inlet (412). The first inlet (410) and the second inlet (412) direct the fluid flow into the cavity (402) in a first cycle (FIG. 4a) and a second cycle (FIG. 4b) which drive the movement of the piston (218) within the cavity (402).

In accordance with one or more embodiments, the jet element (214) may have a third outlet (not pictured) disposed on a side wall of the jet element (214) that allows the fluid flow to bypass the inner cylinder (400), enter the remainder of the tubular apparatus (200), and provide pressure balance within the tubular apparatus (200). The fluid is able to flow around the inner cylinder (400) and cylinder gland (408) using outer ring cuts (414) machined into the outer surface of the inner cylinder (400) and cylinder gland (408).

The cylinder head (404) is located on a lateral end of the inner cylinder (400), and the cylinder gland (408) is connected on the opposite lateral end of the inner cylinder (400). The metal ring (406) is disposed between the inner cylinder (400) and the cylinder gland (408). The metal ring (406) acts as a fluid seal between the inner cylinder (400) and the cylinder gland (408). The cylinder gland (408) along with the element gland (300) act as a fixture that holds the jet element (214) and the inner cylinder (400) in place within the outer cylinder (204).

Turning back to FIG. 2, the piston (218) has a piston rod (222), and the piston (218) is moveable along the axis (220). The piston (218) is sized such that the piston (218) is unable to exit the cavity (402). However, the piston rod (222) extends from the piston (218), through the cavity (402) of the inner cylinder (400), and through the cylinder gland (408) to be connected to a hammer (224). The piston rod (222) may be connected to the hammer (224) through fitting and soldering.

The cylinder gland (408) may have a spiral ring groove (310) to create a seal between the cylinder gland (408) and the piston rod (222) as fluid is passing from the inner cylinder (400) through the cylinder gland (408). A portion of the piston rod (222) is disposed within the middle joint (206). The middle joint (206) compresses the cylinder gland (408) and connects the outer cylinder (204) to the outer tube (208).

As the piston (218) reciprocates along the axis (220), the piston (218) moves the hammer (224) in the same direction along the same axis (220). The fluid flows from the inner cylinder (400), through the cylinder gland (408), and into the middle joint (206). The fluid flows around the outside of the piston rod (222) and the hammer (224) in the middle joint (206). A portion of the hammer (224) is disposed within the outer tube (208), and a second portion of the hammer (224) is disposed within the middle joint (206).

A bearing (600) is disposed between the hammer (224) and the outer tube (208). The bearing (600) reduces friction, and wear, between the moving parts of the tubular apparatus (200). Different embodiments of the bearing (600) design are shown in FIGS. 6a-8. The fluid flows from the middle joint (206) into the outer tube (208). The fluid flows around the outside of the hammer (224) and through the bearing (600).

The hammer (224) is connected to the anvil (500). The anvil (500) may be disposed within the outer tube (208), the octagonal sleeve (210), and an external environment, such as the wellbore (102). Because of the connection between the piston (218), hammer (224), and anvil (500), as the piston (218) reciprocates along the axis (220), so do the hammer (224) and the anvil (500). FIG. 5 shows a detailed cross section of the anvil (500). The fluid flows into the anvil (500) through a channel (502). The anvil (500) has a bit head (504). The bit head (504) may have one or more nozzles (not pictured) that allow the fluid to flow from the inside of the anvil (500) to an external environment, such as the wellbore (102).

The bit head (504) may have a plurality of diamond-enhanced inserts embedded into the face (not pictured) of the bit head (504). The face of the bit head (504) is the portion of the bit head (504) that interacts with the bottom of the wellbore (102). The face of the bit head (504) may also be shaped and designed for optimal bit-face cleaning and directional control. The anvil (500) may have the spiral ring groove (310) machined into the outer circumferential surface (508) of the anvil (50) to act as a seal when a fluid passes between the anvil (500) and the octagonal sleeve (210) using the throttling effect.

FIGS. 6a and 6b show a bearing (600) in accordance with one or more embodiments. Components shown in FIGS. 6a and 6b that are similar to or the same as components shown in FIGS. 1-5 have not been redescribed for purposes of readability and have the same description and function as described above. FIG. 6a shows a cross section of the bearing (600) installed on the outer tube (208) of FIG. 2. The outer tube (208) has an orifice (602) where the hammer (224) and anvil (500) may be disposed. FIG. 6b shows a cross section of the outer tube (208) and bearing (600) along the axis B-B′.

A plurality of balls (604) may be evenly spaced in at least one ring shape on an inner circumferential surface (606) of the outer tube (208). Each ball may be alternated with an inlet (605) component (as shown in FIG. 6b). The inlets (605) allow the fluid to flow through the bearing (600). In one or more embodiments, there may be three rings of balls (604) on the inner circumferential surface (606) of the outer tube (208) as shown in FIG. 6a.

The balls (604) may be able to rotate as the hammer (224) is reciprocated along the axis (220). The balls (604) may be made out of any durable material, such as steel. The balls (604) may be installed into the outer tube (208) by initially installing the balls (604) on a ball bearing ring (not pictured) and threading the ball bearing ring into the inside of the outer tube (208).

FIGS. 7a-7e show a bearing (600) in accordance with one or more embodiments. Components shown in FIGS. 7a-7e that are similar to or the same as components shown in FIGS. 1-6b have not been redescribed for purposes of readability and have the same description and function as described above. FIGS. 7a-7d show the hammer (224) of FIG. 2 with a shield ring (700) disposed circumferentially around the hammer (224).

Specifically, FIG. 7a shows a cross section of the hammer (224) and the bearing (600), FIG. 7b shows a see-through view of the bearing (600) around a solid view of the hammer (224), FIG. 7c shows a cross section of the bearing (600) and the hammer (224) along axis C-C′, and FIG. 7d shows a see-through view of the bearing (600) and the hammer (224). FIG. 7e shows a cut away view of the shield ring (700).

The hammer (224) is rotatable and movable within the shield ring (700). In further embodiments, the shield ring (700) is disposed between the hammer (224) and the outer tube (208). The space between the shield ring (700) and the hammer (224) is a lubricant cavity (702). The lubricant cavity (702) may hold a lubricant. A plurality of balls (604) may be disposed along an inner circumferential surface (704) of the shield ring (700).

A groove may be machined into the shield ring (700) to hold the balls (604). The balls (604) may be organized in a plurality of straight lines along the shield ring (700) to form a roller array, as shown in FIGS. 7b and 7d. The roller array centralizes the hammer (224), supports the radial forces applied on the hammer (224), and reduces friction in an axial direction for improved impact transmission efficiency.

The balls (604) may be able to rotate as the hammer (224) reciprocates through the shield ring (700). The shield ring (700) may be designed with a space (706) machined into the outer body of the shield ring (700), between the shield ring (700) and the outer tube (208), such that fluid is able to pass through the bearing (600) using the space (706). There may be three or more spaces (706) that allow for the flow of the fluid and these spaces (706) may be evenly distributed around the shield ring (700) as shown in FIG. 7c

FIG. 8 shows a bearing (600) in accordance with one or more embodiments. Components shown in FIG. 8 that are similar to or the same as components shown in FIGS. 1-7e have not been redescribed for purposes of readability and have the same description and function as described above. Specifically, FIG. 8 shows a cut away view of the outer tube (208) around a solid view of the hammer (224).

At least one pillar (800) is mounted to the hammer (224). The pillar (800) is disposed between the hammer (224) and the outer tube (208). The pillar (800) may be a rectangle-like shape made of a durable material, such as steel. In one or more embodiments, there are eight pillars (800) mounted on the hammer (224). A plurality of reinforcement blocks (802) are machined into each pillar (800) and into an inner circumferential surface (804) of the outer tube (208).

The reinforcement blocks (802) may be made of a durable material, such as tungsten carbide, thermally stable polycrystalline, polycrystalline diamond compact, etc. The reinforcement blocks (802) may be embedded into the pillars (800) and the inner circumferential surface (804) of the outer tube (208) to form a contact interface. The reinforcement blocks (802) prevent the wear of the hammer (224) and the outer tube (208) and serve as a sliding/rotation movement pair. The pillars (800) of the hammer (224) may be spaced out to create flow paths between the neighboring pillars (800).

FIG. 9 shows a flowchart in accordance with one or more embodiments. The flowchart outlines a method for extending a wellbore (102). While the various blocks in FIG. 9 are presented and described sequentially, one of ordinary skill in the art will appreciate that some or all of the blocks may be executed in different orders, may be combined or omitted, and some or all of the blocks may be executed in parallel. Furthermore, the blocks may be performed actively or passively.

Initially, a tubular apparatus (200) is provided (S900). The tubular apparatus (200) may include an upper joint (202) threaded into an outer cylinder (204), an inner cylinder (400) having a cavity (402) disposed within the outer cylinder (204), and a piston (218) having a piston rod (222). The piston (218) may be disposed within the cavity (402) of the inner cylinder (400) and moveable along an axis (220).

The tubular apparatus (200) may further include a metal ring (406) disposed between the inner cylinder (400) and a cylinder gland (408). The piston rod (222) may extend through the cylinder gland (408) to a hammer (224). A portion of the hammer (224) may be disposed within an outer tube (208). A bearing (600) may be disposed between the hammer (224) and the outer tube (208). An anvil (500), having a bit head (504), may be connected to the hammer (224).

The tubular apparatus (200) is run into the wellbore (102) (S902). The tubular apparatus (200) may be run into the wellbore (102) as a drill bit (112) on a drill string (108). The tubular apparatus (200) is actuated to hammer the bit head (504) against a bottom of the wellbore (102) (S904). The tubular apparatus (200) may be actuated by pumping a fluid along a flow path (212) within the tubular apparatus (200). The fluid may be any type of fluid known in the art such as a drilling mud.

The fluid drives the piston (218) along the axis (220) to create the hammer motion of the bit head (504). The bottom of the wellbore (102) is broken down to extend the wellbore (102) (S906) using the hammering motion of the bit head (504). As the fluid follows the flow path (212) through the tubular apparatus (200), the spiral ring groove (310) on the element gland (300), cylinder gland (408), and anvil (500) creates a seal using the throttling effect as a fluid passes through the spiral ring groove (310).

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.

Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

1. A tubular apparatus comprising: an upper joint connected to an outer cylinder;an inner cylinder, having a cavity, disposed within the outer cylinder;a piston, having a piston rod, the piston disposed within the cavity of the inner cylinder and moveable along an axis;a metal seal disposed between the inner cylinder and a cylinder gland, wherein the piston rod extends through the cylinder gland to a hammer and a portion of the hammer is disposed within an outer tube;a bearing disposed between the hammer and the outer tube; andan anvil, having a bit head, connected to the hammer.

2. The tubular apparatus of claim 1, wherein the bearing further comprises a plurality of balls evenly spaced in at least one ring shape on an inner circumferential surface of the outer tube.

3. The tubular apparatus of claim 1, wherein the bearing further comprises a shield ring disposed between the outer tube and the hammer.

4. The tubular apparatus of claim 3, wherein the shield ring and the hammer define a lubricant cavity holding a lubricant.

5. The tubular apparatus of claim 3, wherein the bearing further comprises a plurality of balls disposed along an inner circumferential surface of the shield ring.

6. The tubular apparatus of claim 1, wherein the bearing further comprises at least one pillar mounted to the hammer.

7. The tubular apparatus of claim 6, wherein the at least one pillar is disposed between the hammer and the outer tube.

8. The tubular apparatus of claim 6, wherein the bearing further comprises a plurality of reinforcement blocks machined into the at least one pillar and an inner circumferential surface of the outer tube.

9. The tubular apparatus of claim 1, further comprising an element gland having a central hole and a plurality of shunt holes disposed axially around the central hole.

10. The tubular apparatus of claim 9, wherein the element gland is disposed within the outer cylinder and adjacent to a distal portion of the upper joint.

11. The tubular apparatus of claim 9, further comprising a jet element disposed directly within the outer cylinder and located between the element gland and the inner cylinder.

12. The tubular apparatus of claim 11, wherein the central hole and the plurality of shunt holes guide a fluid into the jet element to move the piston along the axis.

13. The tubular apparatus of claim 1, further comprising a middle joint threaded into the outer cylinder and the outer tube.

14. The tubular apparatus of claim 13, wherein a second portion of the hammer is disposed within the middle joint.

15. The tubular apparatus of claim 1, further comprising an octagonal sleeve threaded into the outer tube.

16. The tubular apparatus of claim 15, wherein the anvil further comprises a spiral ring groove configured to seal between the anvil and the octagonal sleeve.

17. A method for extending a wellbore, the method comprising: providing a tubular apparatus comprising: an upper joint threaded into an outer cylinder;an inner cylinder, having a cavity, disposed within the outer cylinder;a piston, having a piston rod, the piston disposed within the cavity of the inner cylinder and moveable along an axis;a metal seal disposed between the inner cylinder and a cylinder gland, wherein the piston rod extends through the cylinder gland to a hammer and a portion of the hammer is disposed within an outer tube;a bearing disposed between the hammer and the outer tube; andan anvil, having a bit head, connected to the hammer, andrunning the tubular apparatus into the wellbore;actuating the tubular apparatus to hammer the bit head against a bottom of the wellbore; andbreaking down the bottom of the wellbore to extend the wellbore.

18. The method of claim 17, wherein actuating the tubular apparatus further comprises pumping a fluid along a flow path within the tubular apparatus.

19. The method of claim 18, wherein pumping the fluid along the flow path further comprises driving the piston along the axis.

20. The method claim 19, wherein pumping the fluid along the flow path further comprises creating a seal using a throttling effect of a fluid in a spiral ring groove.