US20230193696A1

US20230193696A1 - Hybrid drilling and trimming tool and methods

Info

Publication number: US20230193696A1
Application number: US17/644,991
Authority: US
Inventors: Sameeh Issa Batarseh
Original assignee: Saudi Arabian Oil Co
Current assignee: Saudi Arabian Oil Co
Priority date: 2021-12-17
Filing date: 2021-12-17
Publication date: 2023-06-22

Abstract

A system includes a drill pipe, a fiber optic housing, a laser housing, a conduit, and a fiber optic cable. The drill pipe extends from a surface location into the wellbore. The fiber optic housing is connected to the drill pipe. The laser housing is connected to the fiber optic housing and houses a laser. The drill bit, the laser housing, the fiber optic housing, and the drill pipe are configured to rotate. The conduit extends through the drill pipe, the fiber optic housing, the laser housing, and the drill bit. The fiber optic cable is housed in the fiber optic housing, is disposed within the conduit, and extends from the surface location to the laser located in the laser housing. The laser emits a laser beam into the wellbore. Rotation of the laser housing rotates the laser beam in a circular plane perpendicular to the wellbore.

Description

BACKGROUND

In the oil and gas industry, hydrocarbons are located in porous reservoirs far beneath the Earth's surface. Wells are drilled into these reservoirs to produce the hydrocarbons. A well includes a wellbore, drilled into the Earth's surface, supported by one or more strings of casing cemented in place. A wellbore is drilled using a drill bit designed to break apart downhole rock formations. Drill bits are known to create irregular-shaped holes having washout, cavities, ledges, etc. Irregular-shaped holes can lead to stuck pipes, inefficient mud circulation, hole collapse, etc.

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.
The present disclosure presents, in accordance with one or more embodiments, a system and a method for drilling a well. The system includes a drill pipe, a fiber optic housing, a laser housing, a conduit, and a fiber optic cable. The drill pipe extends from a surface location into the wellbore. The drill pipe is configured to transport a fluid from the surface location to a drill bit. The fiber optic housing is connected to the drill pipe. The laser housing is connected to the fiber optic housing and is configured to house a laser. The drill bit, the laser housing, the fiber optic housing, and the drill pipe are configured to rotate. The conduit extends through the drill pipe, the fiber optic housing, the laser housing, and the drill bit. The fiber optic cable is housed in the fiber optic housing, is disposed within the conduit, and extends from the surface location to the laser located in the laser housing. The laser uses energy from the fiber optic cable to emit a laser beam into the wellbore. Rotation of the laser housing rotates the laser beam in a circular plane perpendicular to the wellbore.
The method includes making up a drill string with drill pipe, a fiber optic housing, a laser housing, and a drill bit, running the drill string into the wellbore, transmitting energy from a surface location to a laser located in the laser housing using a fiber optic cable, emitting a laser beam, from the laser, against the wellbore, rotating the drill bit, the laser housing, the fiber optic housing, and the drill pipe to rotate the laser beam in a circular plane perpendicular to the wellbore, and extending the wellbore using the drill bit and the laser beam.
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.

FIGS. 2A and 2B show a laser system in accordance with one or more embodiments.

FIG. 3 shows the laser system deployed in a wellbore in accordance with one or more embodiments.

FIG. 4 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, 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 may 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 a top 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 (130) 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).
As explained above, the wellbore (102) is drilled using the drill bit (112). Drill bits are known to create irregular-shaped holes having washout, cavities, ledges, etc. Irregular-shaped holes can lead to stuck pipes, inefficient mud circulation, hole collapse, etc. Therefore, the ability to correct or create a more symmetrical and smoother (i.e., trimmed) hole, while drilling the wellbore (102), is beneficial. As such, embodiments disclosed herein present systems and methods that equip a drill bit (112) with a laser system. The laser system is placed directly up hole from the drill bit (112) on the drill string (108) and is used to smooth (i.e., trim) the walls of the wellbore (102) as the drill bit (112) drills the wellbore (102)
FIGS. 2 a and 2 b show a laser system in accordance with one or more embodiments. FIG. 2 a shows a partial cross section of the laser system and FIG. 2 b shows a side view of the laser system. Components of FIGS. 2 a and 2 b that are the same as or similar to components shown in FIG. 1 have not been redescribed for purposed of readability and have the same function and purpose as described above. The laser system includes drill pipe (109), a rotational attachment (200), a fiber optic housing (202), a laser housing (204), and a drill bit (112).
The drill bit (112) may be any drill bit (112) known in the art such as a roller cone drill bit, a fixed cutter drill bit, or a hybrid drill bit. In accordance with one or more embodiments, the drill bit (112) is a polycrystalline diamond compact fixed cutter drill bit. A conduit (206) runs through the laser system from a surface location (not pictured) through the drill bit (112). The surface location may be any location of the surface of the Earth, such as on a drilling rig floor.
Specifically, the conduit (206) extends from the surface location, through the drill pipe (109), the laser housing (204), the fiber optic housing (202), and the drill bit (112). The conduit (206) may change in size from component to component without departing from the scope of the disclosure herein. Further, the conduit (206) may be a singular hole through the geometric center of the component, such as shown in the drill pipe (109) in FIG. 2 a . Or such as in the case of the drill bit (112), the conduit (206) may be a plurality of nozzles (not pictured) that extend, at least, partially through the component.
The conduit (206) may be hydraulically connected, at the surface location, to a fluid or drilling mud system, such as the mud pit (132). The drill pipe (109), using the conduit (206), may transport the fluid from the surface location into the wellbore (102). Specifically, the fluid may exit the drill bit (112) through nozzles (not pictured) into the wellbore (102). The drill pipe (109) may be hollow, thin-walled piping made out of a durable material, such as steel or aluminum-alloy. The drill pipe (109) may include one or more joints of drill pipe (109). The drill pipe (109) may be a part of a drill string (108) having a BHA (110). In accordance with one or more embodiments, drill pipe (109) may be a drill collar, a drilling sub, or another portion of the drill string (108) without departing from the scope of the disclosure herein.
The drill pipe (109) is connected to the rotational attachment (200) and the rotational attachment (200) is connected to the fiber optic housing (202). The fiber optic housing (202) is connected to the laser housing (204), and the laser housing (204) is connected to the drill bit (112). These connections may be made by any means known in the art such as threading or welding. Further, the fiber optic housing (202) and the laser housing (204) may be made of a similar material as the drill pipe (109). In other embodiments, the drill pipe (109) may be directly connected to the laser housing (204) without departing from the scope of the disclosure herein.
At least one fiber optic cable, located within the conduit (206) of the drill pipe (109), the rotational attachment (200), and the fiber optic housing (202), may extend from the surface location to the laser housing (204). The fiber optic housing (202) protects the fiber optic cable. The rotational attachment (200) controls the rotational speed of the fiber optic housing (202) and the laser housing (204). The fiber optic cable is a network cable that contains strands of glass fibers inside of an insulated casing. The fiber optic cable carries energy from the surface location to the laser housing (204) using pulses of light generated by small lasers or light-emitting diodes. In accordance with one or more embodiments, there may be multiple fiber optic cables in the laser system. For example, a first fiber optic cable (208) and a second fiber optic cable (210) may be run from the surface location to the laser housing (204).
The first fiber optic cable (208) and the second fiber optic cable (210) may be run inside of the drill pipe (109), from the surface location, using a coiled tubing unit (not pictured). Specifically, the coiled tubing is run inside of the drill pipe (109) after the drill string (108) has been run into the wellbore (102). When the coiled tubing bottom hole assembly reaches the laser housing (204), the first fiber optic cable (208) and the second fiber optic cable (210) may be disconnected from the coiled tubing and connected to the laser housing (204).
In other embodiments, the fiber optic cables (208, 210) are run into the drill pipe (109) as the drills string (108) is being made up at the surface location. The fiber optic cables (208, 210) are not fixed to the dill pipe (1090, rather the fiber optic cables (208, 210) are located within the conduit (206) of the drill pipe (109), thus, they do not rotate with the rotation of the drill pipe (109). However, the fiber optic cables (208, 210) connect to the rotational attachment (200), so the fiber optic cables (208, 210) rotate with the rotational attachment (200).
At least one laser, located in the laser housing (204), may be connected to the fiber optic cable. In accordance with one or more embodiments, a first laser (212) and a second laser (214) are located within the laser housing (204). The first fiber optic cable (208) is connected to the first laser (212) and the second fiber optic cable (210) is connected to the second laser (214). The fiber optic housing (202) changes the orientation of the fiber optic cables (208, 210) from one orientation to another (i.e., from vertical to horizontal) such that the fiber optic cables (208, 210) may be properly connected to the lasers (212, 214) in the laser housing (204). The first laser (212) and the second laser (214) may be fiber lasers, or, more specifically, Ytterbium fiber lasers. A fiber laser is a laser in which the active gain medium is an optical fiber doped with rare earth elements. An Ytterbium fiber laser uses Ytterbium to dope the optical fiber.
The laser housing (204) may be made out of any durable material known in the art, such as steel. The laser housing (204) may have a plurality of insulated connection ports (not pictured) that allow for connection between the fiber optic cables and the lasers within the laser housing (204). The first laser (212) and the second laser (214) may be located within the laser housing (204) such that they extend from the inside of the laser housing (204) to an external environment of the laser housing (204), such as the wellbore (102), as shown in FIGS. 2 a and 2 b.
A first laser beam (216) may be emitted from the first laser (212) using energy transported from the surface location using the first fiber optic cable (208). A second laser beam (218) may be emitted from the second laser (214) using energy transported from the surface location using the second fiber optic cable (210). The first laser beam (216) and the second laser beam (218) are emitted from the laser housing (204) into an external environment, such as the wellbore (102). The first laser beam (216) and the second laser beam (218) may be emitted along a plane perpendicular to the body of the laser housing (204), as shown in FIGS. 2 a and 2 b.
In accordance with one or more embodiments, the drill string (108), the drill pipe (109), the rotational attachment (200), the fiber optic housing (202), the laser housing (204) and the drill bit (112) are configured to rotate. The listed components may rotate due to a top drive (130) or a rotary table at the surface location. The rotation of the laser housing (204) causes the first laser beam (216) and the second laser (214) beam to rotate in a circular plane (220) perpendicular to the laser housing (204) and the external environment, such as the wellbore (102). In accordance with one or more embodiments, the rotational attachment (200) is designed to rotate the fiber optic housing (202) and the laser housing (204) at a different rotational speed than the drill pipe (109) and the drill bit (112). This is because the rotational speed of the first laser beam (216) and the second laser beam (218) may need to be controlled based on the formation the wellbore (102) is extending through.
In further embodiments, the first laser (212) and the second laser (214) each include a lens (not pictured) connected to an end of the first fiber optic cable (208) and the second fiber optic cable (210), respectively. The lens may be designed to control a shape of the first laser beam (216) and the second laser beam (218). For example, the length of the focal distance of the lens controls the diameter of the laser beam, thus the greater the surface onto which the energy of the laser is applied.
FIG. 3 shows the laser system deployed in a wellbore (102) in accordance with one or more embodiments. Components of FIG. 3 that are the same as or similar to components shown in FIGS. 1-2 b have not been redescribed for purposes of readability and have the same function and description as outlined above. As explained above, the wellbore (102) is the hole being drilled into the surface of the Earth. The wellbore (102) is delineated by a wellbore wall (300).
FIG. 3 shows the laser system, described in FIGS. 2 a and 2 b , operationally deployed in the wellbore (102). The first laser beam (216) and the second laser beam (218) are shown as being emitted from the laser housing (204). The first laser beam (216) and the second laser beam (218) are directed at the wellbore wall (300).
The first laser beam (216) and the second laser beam (218) may be rotating on a circular plane (220) that is perpendicular to the wellbore (102) due to the rotation of the drill pipe (109), fiber optic housing (202), laser housing (204), and drill bit (112). Thus, the first laser beam (216) and the second laser beam (218) are able to break apart and remove the rock in the wellbore wall (300) in a symmetrical manner to smooth the wellbore (102).
FIG. 3 shows the wellbore wall (300) having a smooth section (306) and an irregular section (308). The irregular section (308) has crevices, washouts, etc. due to the drill bit (112). The smooth section (306) has a relatively smooth and regular surface due to the application of the laser system on the wellbore wall (300).
A mud motor (302) may be connected to the drill pipe (109) and be located up hole from the fiber optic housing (202). The mud motor (302) may be any mud motor (302) known in the art and may have a rotor-stator interface (304). The rotor-stator interface (304) is located in the conduit (206) of the mud motor (302) section of the drill string (108). Thus, a fluid, such as drilling mud, being pumped from the surface location through the drill string (108) passes through the rotor-stator interface (304).
The fluid pressure and the rotor-stator interface (304) causes the mud motor (302) and any components of the drill string (108) located downhole from the mud motor (302) (i.e., the drill pipe (109), fiber optic housing (202), laser housing (204), and drill bit (112)) to rotate. Thus, these components are able to rotate without rotating the entire drill string (108), from the surface location, using the top drive (130) or the rotary table. In further embodiments, the components are able to rotate at a higher speed than the rotation of the drill string (108) while the drill string (108) is rotating and while fluid is being pumped through the mud motor (302).
FIG. 4 shows a flowchart in accordance with one or more embodiments. The flowchart outlines a method for drilling a wellbore (102). While the various blocks in FIG. 4 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 drill string (108) is made up with drill pipe (109), a fiber optic housing (202), a laser housing (204), and a drill bit (112) (S400). The drill bit (112) is connected to the laser housing (204), the laser housing (204) is connected to the fiber optic housing (202), and the fiber optic housing (202) is connected to the drill pipe (109). The fiber optic housing (202) may be connected to the drill pipe (109) by a rotational attachment (200). All connections may be performed using any means in the art, such as threading the components together.
Further, a first fiber optic cable (208) and a second fiber optic cable (210) are run into a conduit (206) of the drill pipe (109), rotational attachment (200), and fiber optic housing (202). The fiber optic cables (208, 210) may be run into the conduit (206) using a coiled tubing unit after the drills string (108) is made up, or the fiber optic cables (208, 210) are run into the conduit (206) from the rig floor as the drill string (108) is being made up.
The first fiber optic cable (208) and second fiber optic cable (210) are connected to a first laser (212) and a second laser (214), both located in the laser housing (204). In further embodiments, a mud motor (302) may be installed on the drill pipe (109) and be located up hole from the fiber optic housing (202). The mud motor (302) has a rotor-stator interface (304) that uses a fluid pressure to rotate the mud motor (302) and any drill string (108) components located downhole from the mud motor (302).
The drill string (108) is run into the wellbore (102) (S402). In accordance with one or more embodiments, the drill bit (112) enters the wellbore (102) followed by the laser housing (204). Energy is transmitted from a surface location to the laser(s) located in the laser housing (204) using the fiber optic cable(s) (208, 210) (S404). Laser beam(s) are emitted from the laser(s) against the wellbore (102) (S406). The fiber optic cable may be the first fiber optic cable (208) and the second fiber optic cable (210). The laser may be the first laser (212) and the second laser (214). The first laser (212) may emit a first laser beam (216), and the second laser (214) may emit a second laser beam (218).
The drill bit (112), the laser housing (204), the fiber optic housing (202), and the drill pipe (109) are rotated to rotate the laser beam(s) in a circular plane (220) perpendicular to the wellbore (102) (S408). A top drive (130) or a rotary table may be used to rotate the entire drill string (108) from the surface of the Earth. A fluid, such as a drilling mud, may be pumped into the conduit (206) of the drill string (108) to operate the mud motor (302) and rotate the components located downhole from the mud motor (302).
The wellbore (102) is extended using the drill bit (112) and the laser beam(s) (S410). Specifically, the drill bit (112) breaks apart the wellbore wall (300) to extend, or enlarge, the wellbore (102) which creates an irregular section (308) of the wellbore (102). The rotating laser beams (216, 218) follow the drill bit (112) to break apart the irregular section (308) and create the smooth section (306). Embodiments disclosed above outline a laser system using two fiber optic cables, two lasers, and two laser beams; however, any number of fiber optic cables, lasers, or laser beams may be used without departing from the scope of the disclosure herein.
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(f) 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

What is claimed:

1. A system for drilling a wellbore, the system comprising:

a drill pipe extending from a surface location into the wellbore, the drill pipe configured to transport a fluid from the surface location to a drill bit;

a fiber optic housing connected to the drill pipe;

a laser housing connected to the fiber optic housing and configured to house a laser, wherein the drill bit, the laser housing, the fiber optic housing, and the drill pipe are configured to rotate;

a conduit extending through the drill pipe, the fiber optic housing, the laser housing, and the drill bit; and

a fiber optic cable is housed in the fiber optic housing, is disposed within the conduit, and extends from the surface location to the laser located in the laser housing, wherein the laser uses energy from the fiber optic cable to emit a laser beam into the wellbore, wherein rotation of the laser housing rotates the laser beam in a circular plane perpendicular to the wellbore.

2. The system of claim 1, wherein the laser further comprises a lens connected to an end of the fiber optic cable, the lens controlling a shape of the laser beam.

3. The system of claim 1, wherein the laser comprises an Ytterbium fiber laser.

4. The system of claim 1, wherein the fiber optic cable further comprises a first fiber optic cable and a second fiber optic cable.

5. The system of claim 4, wherein the laser further comprises a first laser and a second laser.

6. The system of claim 5, wherein the first fiber optic cable is connected to the first laser and the second fiber optic cable is connected to the second laser to emit a first laser beam and a second laser beam, respectively.

7. The system of claim 1, further comprising a rotational attachment disposed between the drill pipe and the fiber optic housing.

8. The system of claim 7, wherein the rotational attachment controls a rotational speed of the laser beam.

9. The system of claim 1, further comprising a mud motor connected to the drill pipe and located up hole from the fiber optic housing.

10. The system of claim 9, wherein the mud motor comprises a rotor-stator interface which uses the fluid to rotate the drill bit, the laser housing, the fiber optic housing, and the drill pipe.

11. A method for drilling a wellbore, the method comprising:

making up a drill string with drill pipe, a fiber optic housing, a laser housing, and a drill bit;

running the drill string into the wellbore;

transmitting energy from a surface location to a laser located in the laser housing using a fiber optic cable;

emitting a laser beam, from the laser, against the wellbore;

rotating the drill bit, the laser housing, the fiber optic housing, and the drill pipe to rotate the laser beam in a circular plane perpendicular to the wellbore; and

extending the wellbore using the drill bit and the laser beam.

12. The method of claim 11, wherein emitting the laser beam from the laser further comprises changing a shape of the laser beam using a lens connected to an end of the fiber optic cable.

13. The method of claim 11, wherein emitting the laser beam further comprises emitting the laser beam from an Ytterbium fiber laser.

14. The method of claim 11 wherein transmitting energy from the surface location to the laser located in the laser housing further comprises using a first fiber optic cable and a second fiber optic cable.

15. The method of claim 14, wherein transmitting energy from the surface location using the first fiber optic cable and the second fiber optic cable further comprises transmitting energy from the surface location to a first laser and a second laser located in the laser housing.

16. The method of claim 15, wherein emitting the laser beam further comprises emitting a first laser beam from the first laser and a second laser beam from the second laser against the wellbore.

17. The method of claim 11, wherein making up the drill string further comprises connecting the drill pipe to the fiber optic housing using a rotational attachment.

18. The method of claim 17, wherein rotating the drill bit, the laser housing, the fiber optic housing, and the drill pipe further comprises using the rotational attachment to control a rotational speed of the laser beam.

19. The method of claim 11, wherein making up the drill string further comprises installing a mud motor up hole from the fiber optic housing on the drill pipe.

20. The method of claim 19, wherein rotating the drill bit, the laser housing, the fiber optic housing, and the drill pipe further comprises pumping a fluid into a rotor-stator interface of the mud motor.