CA2958865A1 - Method and apparatus for drilling a wellbore for recovery of hydrocarbons from a hydrocarbon reservoir - Google Patents

Abstract

A method of drilling a wellbore for use in a hydrocarbon recovery operation, includes receiving signals from at least two gyroscopes coupled to a drill during drilling of the wellbore, the signals indicative of a change in orientation of the gyroscopes, analyzing the signals from the gyroscopes to identify a location of the drill relative to a previously identified location, comparing the location of the drill to a target location of the drill, and, in response to determining that the location of the drill differs from a target location, adjusting a direction of the drill based on the identified location of the drill, wherein drilling of the wellbore is continuous during receipt of the signals and analysis of the signals.

Description

METHOD AND APPARATUS FOR DRILLING A WELLBORE FOR RECOVERY
OF HYDROCARBONS FROM A HYDROCARBON RESERVOIR
TECHNICAL FIELD
[0001] The present application relates to directional drilling of wellbores in a hydrocarbon reservoir, such as wellbores for use as injection or production wells in steam-assisted gravity drainage (SAGD) processes.
BACKGROUND DISCUSSION

[0002] Extensive deposits of viscous hydrocarbons exist around the world, including large deposits in the northern Alberta oil sands that are not susceptible to standard oil well production technologies. The hydrocarbons in such deposits are too viscous to flow at commercially relevant rates at the temperatures and pressures present in the reservoir. For such reservoirs, thermal techniques may be utilized to heat the reservoir to mobilize the hydrocarbons and produce the heated, mobilized hydrocarbons from wells. One such technique for recovering viscous hydrocarbons using alternating injection of steam and production of fluid from a well in a hydrocarbon reservoir is known as cyclic steam stimulation (CSS). One such technique for utilizing a horizontal well for injecting heated fluids and producing hydrocarbons is described in U.S. Patent No. 4,116,275, which also describes some of the problems associated with the production of mobilized viscous hydrocarbons from horizontal wells.

[0003] One thermal method of recovering viscous hydrocarbons using spaced horizontal wells is known as steam-assisted gravity drainage (SAGD).
SAGD utilizes gravity in a process that relies on the density difference of the mobile fluids to achieve a desirable vertical segregation within the reservoir.
Various embodiments of the SAGD process are described in Canadian Patent No.
1,304,287 and U.S. Patent No. 4,344,485. In the SAGD process, pressurized steam is delivered through an upper, horizontal, injection well, into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, horizontal, production well. The injection and production wells are typically situated in the lower portion of the reservoir, with the producer located close to the base of the hydrocarbon deposit to collect the hydrocarbons that flow toward the base of the deposit.

[0004] The relative locations of the injection and the production wells are important in the recovery of hydrocarbons. In particular, it is desirable that the production well be parallel and spaced vertically from the injection well. It is therefore desirable to control the location and direction of the drill during drilling of the injection and production wells.
SUMMARY

[0005] In an aspect of the present disclosure, there is provided a method of drilling a wellbore for use in a hydrocarbon recovery operation. The method includes receiving signals from at least two gyroscopes coupled to a drill during drilling of the wellbore, the signals indicative of a change in orientation of the gyroscopes, analyzing the signals from the gyroscopes to identify a location of the drill relative to a previously identified location, comparing the location of the drill to a target location of the drill, and, in response to determining that the location of the drill differs from a target location, adjusting a direction of the drill based on the location of the drill, wherein drilling of the wellbore is continuous during receipt of the signals and analysis of the signals.

[0006] In another aspect, an apparatus for drilling a wellbore for use in a hydrocarbon recovery operation is provided. The apparatus includes a drill for creating the wellbore, a component coupled to the drill, a drill string coupled to the component, and at least two gyroscopes coupled to the component and in communication with an external electronic device for providing signals to the electronic device during drilling of the wellbore utilizing the drill, the signals indicative of a change in orientation of the gyroscopes, such that the drill is continuously rotatable to continuously drill the wellbore during receipt of the signals and analysis of the signals.

[0007] Other aspects and features of the present disclosure will become apparent to those of ordinary skill in the art upon review of the following description of specific embodiments in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS

[0008] Embodiments of the present application will now be described, by way of example only, with reference to the attached Figures, wherein:

[0009] FIG. 1 is a sectional view through a reservoir, illustrating a SAGD
well pair;

[0010] FIG. 2 is a sectional side view illustrating a SAGD well pair including an injection well and a production well;

[0011] FIG. 3 is a graph illustrating recovery factor as a function of time for three simulations of injection and production wells;

[0012] FIG. 4 is an end view of a component of an apparatus for drilling a wellbore according to an embodiment, showing hidden detail;

[0013] FIG. 5 is side view of the component of FIG. 4, and showing hidden detail;

[0014] FIG. 6 is sectional side view illustrating an apparatus for drilling a wellbore during drilling according to an embodiment;

[0015] FIG. 7 is a flowchart showing a method of drilling a wellbore for use in hydrocarbon recovery according to an embodiment;

[0016] FIG. 8 is a perspective view of a component of an apparatus for drilling a wellbore according to another embodiment, showing hidden detail;
and

[0017] FIG. 9 is a sectional side view illustrating an apparatus for drilling a wellbore during drilling, according to another embodiment.
DETAILED DESCRIPTION

[0018] For simplicity and clarity of illustration, reference numerals may be repeated among the figures to indicate corresponding or analogous elements.

Numerous details are set forth to provide an understanding of the examples described herein. The examples may be practiced without these details. In other instances, well-known methods, procedures, and components are not described in detail to avoid obscuring the examples described. The description is not to be considered as limited to the scope of the examples described herein.

[0019] The disclosure generally relates to an apparatus and method of drilling a wellbore for use in a hydrocarbon recovery operation. The method includes receiving signals from at least two gyroscopes coupled to a drill during drilling of the wellbore, the signals indicative of a change in orientation of the gyroscopes, analyzing the signals from the gyroscopes to identify a location of the drill relative to a previously identified location, comparing the location of the drill to a target location of the drill, and, in response to determining that the location of the drill differs from a target location, adjusting a direction of the drill based on the location of the drill, wherein drilling of the wellbore is continuous during receipt of the signals and analysis of the signals.

[0020] Reference is made herein to an injection well and a production well.
The injection well and the production well may be physically separate wells.
Alternatively, the production well and the injection well may be housed, at least partially, in a single physical wellbore, for example, a multilateral well.
The production well and the injection well may be functionally independent components that are hydraulically isolated from each other, and housed within a single physical wellbore.

[0021] A steam-assisted gravity drainage (SAGD) process may be utilized for mobilizing viscous hydrocarbons. In the SAGD process, a well pair, including a hydrocarbon production well and a steam injection well are utilized. One example of a well pair is illustrated in FIG. 1 and an example of a hydrocarbon production well 100 and injection well 108 is illustrated in FIG. 2. The hydrocarbon production well 100 includes a generally horizontal segment 102 that extends near the base or bottom 104 of the hydrocarbon reservoir 106. The injection well 108 also includes a generally horizontal segment 110 that is disposed generally parallel to and is spaced generally vertically above the horizontal segment 102 of the hydrocarbon production well 100.

[0022] During SAGD, steam is injected into the injection well 108 to mobilize the hydrocarbons and create a steam chamber 112 in the reservoir 106, around and above the generally horizontal segment 110. In addition to steam injection into the injection well, light hydrocarbons, such as the C3 through alkanes, either individually or in combination, may optionally be injected with the steam such that the light hydrocarbons function as solvents in aiding the mobilization of the hydrocarbons. The volume of light hydrocarbons that is injected is relatively small compared to the volume of steam injected. The addition of light hydrocarbons is referred to as a solvent aided process (SAP).
Alternatively, or in addition to the light hydrocarbons, various non-condensing gases, such as methane or carbon dioxide, may be injected. Viscous hydrocarbons in the reservoir are heated and mobilized and the mobilized hydrocarbons drain under the effect of gravity. The produced emulsion, which includes the mobilized hydrocarbons along with produced water, is collected in the generally horizontal segment 102. The emulsion also includes gases such as steam and production gases from the SAGD process.

[0023] FIG. 3 is a graph illustrating oil recovery factor as a function of time for three simulations of injection and production wells utilized in a SAGD
process. The simulations illustrated include a first simulation of perfectly aligned, straight, production and injection wells that are vertically aligned and are five meters apart. A second simulation is also illustrated in which the injection and production wells are generally 5 meters apart but the injection well meanders from directly vertically above the production well, and thus is not located directly above the production well along the entire length of the injection well. The third simulation is similar to the second simulation with the exception that the meandering is more severe and the toe of the injection well is four meters laterally spaced from the production well and is three meters vertically spaced from the production well. The simulations illustrated in FIG. 3 show that the vertical alignment with consistent vertical spacing of the injection well and the production well, as in the first simulation, results in a better recovery compared to an injection well that meanders from vertical alignment with the production well. Closer control of the relative locations of the injection and production wells is therefore desirable.

[0024] Views of a component of an apparatus for drilling a wellbore are shown in FIG. 4 and FIG. 5. The views shown in FIG. 4 and FIG. 5 show hidden detail for the purpose of the present explanation. In the present example, the component 402, also referred to as a sub, is generally cylindrical and includes a first end 404, which is downhole in relation to a second end 406. Thus, the first end 404 is located farther along the well during the drilling operation than the second end 406. The component 402 couples the drill that is utilized to drill the well, to the drill string 420, which may be drill pipe or coil tubing.

[0025] The component 402 in the present example includes four gyroscopes 408, 410, 412, 414 housed therein. The gyroscopes 408, 410, 412, 414 are fiber-optic gyroscopes that are each coupled to a fiber-optic wire 416 that runs from the respective gyroscope 408, 410, 412, 414, to the surface, and is coupled to an electronic device, such as a computer, that is external to the well, for analyzing signals received from the gyroscopes 408, 410, 412, 414 to determine locations of the gyroscopes 408, 410, 412, 414. The fiber-optic wires 416 are housed in a protective sheath 418, such as a stainless steel line, to protect the fiber-optic wires 416 within the drill string 420. The gyroscopes 408, 410, 412, 414 may be coupled to the fiber-optic wires 416 in any suitable manner.

[0026] Each of the gyroscopes 408, 410, 412, 414 is sealed in a respective pocket within the component 402, to inhibit the ingress of fluid into the pocket and into contact with the gyroscopes 408, 410, 412, 414.

[0027] Referring now to FIG. 6, a sectional side view of the apparatus for drilling a wellbore is shown in the process of drilling the wellbore. The first end of the component 402, in which the four gyroscopes 408, 410, 412, 414 (shown in FIG. 4 and FIG. 5) are housed, is coupled to the drill 602. The drill 602 includes the motor and drill bit. The component 402 does not rotate within the well. The drill 602 is therefore coupled to the first end of the component 402, for example, via a mechanical coupling that facilitates rotation of the drill 602 without rotation of the component 402. Any suitable coupling may be utilized to facilitate rotation of the drill 602 without rotation of the component 402.

[0028] The drill string 420 is coupled to the second end 406 of the component 402. The drill string 420, such as the drill pipe or coil tubing, is coupled to the component 402 by, for example, threaded connection, welding, latching, or any other suitable coupling. In the present example, the drill string is coil tubing.

[0029] Fluid, such as mud, is pumped through the drill string 420, and through the motor of the drill 602, to cause rotation of the drill 602 to create the wellbore, which may be utilized for a production well, such as the well 100 or an injection well, such as the well 108. The fiber-optic wires 416 are protected from the fluid, which may be mud, by the protective sheath 418, also referred to as a conduit. The fiber-optic wires 416 extend through the drill string 420 to the electronic device 606 at the surface.

[0030] Accuracy of determining the location of a gyroscope decreases with the distance of the gyroscope from a reference point, for example, surface or another point in the wellbore. Utilizing multiple gyroscopes, the accuracy is increased in comparison to determination of the location utilizing a single gyroscope. As the drill 602 advances, thus creating the well, the location of the drill 602 is determined based on signals from the gyroscopes 408, 410, 412, 414.
The signals from the gyroscopes 408, 410, 412, 414 are repeatedly analyzed to continuously monitor the location of the drill 602. Thus, the direction of the drill 602 may also be determined and a steering mechanism utilized to adjust the direction of the drill 602 when the drill 602 location differs from a target location.
The direction of the drill 602 may therefore be adjusted based on an identified location or direction.

[0031] A method of drilling a wellbore for use in a hydrocarbon recovery operation is shown in FIG. 7. Some of the processes of the method may be carried out by software executed by, for example, a computer processor of the electronic device 606 located at the surface. Coding of software for carrying out such processes of the method is within the scope of a person of ordinary skill in the art given the present description. The method may contain additional or fewer processes than shown and described. Computer-readable code executable by, for example, the processor to perform parts of the method may be stored in a computer-readable medium.

[0032] Fluid, such as mud, is pumped through the drill string 420, and through the motor of the drill 602, to cause rotation of the drill 602 for drilling the wellbore. During drilling, and thus during pumping of the mud through the drill string 420, the electronic device 606 receives and analyzes signals from the gyroscopes 408, 410, 412, 414 at 702. The signals are indicative of a change in orientation of the gyroscopes and are received at the electronic device via the fiber-optic wires 416. Thus, the drilling is continuous while signals are transmitted from the gyroscopes 408, 410, 412, 414 to the electronic device 606. In other words, the pumping of mud to rotate the drill 602 and rotation of the drill 602 continues while the signals are transmitted from the gyroscopes 408, 410, 412, 414 to the electronic device 606 via the fiber-optic wires 416.

[0033] In the example shown in FIG. 6, the apparatus is utilized to drill a horizontal wellbore for a horizontal well. The apparatus described herein is not limited to drilling wellbores for horizontal wells, however. The apparatus may also be utilized to drill a wellbore for a vertical well, for example. Thus, the present method may be carried out in drilling any wellbore, including a horizontal wellbore and a vertical wellbore.

[0034] The signals from the gyroscopes 408, 410, 412, 414 are analyzed to identify a location of the drill 602 at 704. Alternatively, the signals from the gyroscopes may be analyzed to identify a location of a drill assembly as a whole, the drill assembly comprising the motor, the drill bit, one or more components, and drill string, or an element of the drill assembly other than the drill, for example, component 402, or a position along drill string 420. To identify the location of the drill 602, the signals from each of the gyroscopes 408, 410, 412, 414 are utilized to determine a distance, orientation, and depth of each of the gyroscopes. At 704, a location of the gyroscopes is then determined to identify a present location of the drill relative to a previously identified location.
The previously identified location may be the location of the gyroscopes at the surface or wellhead. The location that is determined may be determined based on an average of locations determined utilizing the signals from each of the gyroscopes.

[0035] The present location that is determined at 704 is then compared to a target location at 706. For example, a difference between the present location of the drill and the target location may be determined. The difference may then be compared to a threshold value at 708. In response to determining that the difference between the present location of the drill and the target location meets or exceeds the threshold value, i.e., the present location differs from the target location, the method continues at 710 and the direction of the drill 602 is adjusted utilizing a steering mechanism.

[0036] In response to determining that the difference between the present location of the drill and the target location does not meet the threshold value at 708, the method continues at 702.

[0037] Rather than comparing a distance to a threshold value, the location that is determined at 704 may be compared to a target zone at 706. When the location is not within the target zone at 708, the process continues at 710 and the direction of the drill 602 is adjusted utilizing the steering mechanism.

[0038] As drilling of the wellbore continues, signals are repeatedly received at the electronic device 606 and these signals are repeatedly analyzed to monitor the drill location during drilling. The drilling is continuous during transmission of the signals from the gyroscopes to the electronic device and during receipt of the signals and analysis at the electronic device. Thus, drilling is not interrupted to determine location of the drill because rotation of the drill continues during the transmission of the signals from the gyroscopes to the electronic device via the fiber-optic wires.

[0039] In the above-described example, four gyroscopes 408, 410, 412, 414 are utilized in the component 402. Optionally, fewer or a greater number of gyroscopes may be utilized. Additional components may also be utilized. For example, three components may be utilized, each including four gyroscopes such that 12 gyroscopes are utilized to determine drill location. The components may be coupled together with the component that is furthest downhole coupled to the drill and the component that is farthest from the drill coupled to the drill string 420. The intermediate component may couple the three components together.
Utilizing 12 gyroscopes, the location and direction of the drill may be determined with much greater accuracy by comparison to use of a single gyroscope.

[0040] A component of an apparatus for drilling a wellbore according to another embodiment is shown in FIG. 8. The example shown in FIG. 8 includes hidden detail for the purpose of the present explanation. The component 802, also referred to as a sub, is generally cylindrical and includes a first end 804, which is downhole in relation to a second end 806 when in use. Thus, the first end 804 is located farther along the well during the drilling operation than the second end 806. The component 802 is coupled to the drill that is utilized to drill the well.

[0041] A plurality of gyroscopes 808, 30 of which are shown, are housed in the component 802. Although 30 gyroscopes are illustrated in this example, any suitable number of gyroscopes may be utilized. The gyroscopes 808 are coupled to a processor 822 and an electromagnetic pulser 824. The processor 822 and the electromagnetic pulser 824 are powered by a power source 826 such as a battery coupled to a motion capture power generator.

[0042] The gyroscopes 808, processor 822, electromagnetic pulser 824 and power source 826 are sealed in pockets within the component 802, to inhibit the ingress of fluid into the pockets and into contact with the gyroscopes 808, processor 822, electromagnetic pulser 824 and power source 826.

[0043] In addition to the gyroscopes 808, one or more magnetometers 828, inclinometers 830, and accelerometers 832 may be housed in the component 802. The one or more magnetometers 828, inclinometers 830, and accelerometers 832 are also coupled to the processor 822 and are sealed in the component to inhibit contact of fluids with the one or more magnetometers 828, inclinometers 830, and accelerometers 832. The one or more magnetometers 828, inclinometers 830, and accelerometers 832 are utilized to provide further information regarding the location of the drill.

[0044] The one or more magnetometers 828 are utilized to identify a magnetic direction, which is a naturally occurring magnetic direction resulting from magnetic north and local magnetic rock. The magnetic direction is then utilized to determine an angular position of the gyroscopes 808 at each time at which signals are taken and sent from the gyroscopes 808 to the processor 822.

The processor 822 may then utilize the additional information in calculating position.

[0045] In addition, one or more accelerometers 832 may be utilized to provide further information. For example, in each rotation of the component 802, the magnetometers 828 may provide a single location, also referred to as an anchor location, and the acceleromoters 832 may be utilized for angular positions between the anchor locations. One or more inclinometers 830 may also optionally be utilized when rotation stops. The inclinometers 830 provide further information during brief periods in which rotation is discontinued.

[0046] Referring now to FIG. 9, a sectional side view of the apparatus including the component of FIG. 8 is shown in the process of drilling the wellbore. The first end 804 of the component 802 is coupled to a drill apparatus, referred to generally as the drill 902, by a mechanical coupling, for example, by threaded connection of the component 802 to a portion of the drill 902. The drill 902 includes the motor and drill bit. In this example, the component 802 rotates within the well.

[0047] A drill string 920 is coupled to the second end 806 of the component 802. The drill string 920, such as the drill pipe or coil tubing, is coupled to the component 802 in any suitable manner.

[0048] Fluid, such as mud, is pumped through the drill string 920, through the component 802, and through the motor of the drill 902, to cause rotation of the drill 902 to create the wellbore, which may be utilized for a production well, such as the well 100, or an injection well, such as the well 108. The gyroscopes 808, processor 822, electromagnetic pulser 824 and power source 826, shown in FIG. 8, are sealed within the component 802 and are thus protected from the fluid, which may be mud.

[0049] During drilling, and thus during pumping of the mud, an electronic device 906 at the surface receives signals indicative of a location of the drill 902 via the electromagnetic pulser 824. Thus, the drilling is continuous while signals are transmitted to the electronic device 906. In other words, the pumping of mud to rotate the drill 902 and rotation of the drill 902 continue while the signals are transmitted at 702 (as shown in FIG. 7).

[0050] Accuracy of determining the location of a gyroscope decreases with the distance of the gyroscope from a reference point, for example, surface or another point in the wellbore. Utilizing multiple gyroscopes, the accuracy is increased in comparison to determination of the location utilizing a single gyroscope. As the drill 902 advances, thus creating the well, the location of the drill 902 is determined based on signals from the gyroscopes 808.

[0051] In addition, signals from the one or more magnetometers, inclinometers, and accelerometers are received at the processor 822. The signals from the gyroscopes 808 as well as signals from, for example, magnetometers, inclinometers, and accelerometers, are repeatedly received by the processor 822 and the signals are aggregated or partially analyzed at the processor 822. A resulting signal is transmitted to the electronic device 906 at 702 for further processing by the electronic device 906. Thus, the signals are analyzed by one or both of the processor 810 and the electronic device 906 to continuously monitor the location of the drill 902 at 704.

[0052] A present location of the drill 902 relative to a previously identified location is determined at 704. The previously identified location may be the location of the gyroscopes at the surface or wellhead. The location that is determined may be determined based on an average of locations determined utilizing the signals from each of the gyroscopes.

[0053] The present location is compared to a target location at 706.
Thus, the direction of the drill 902 may also be determined and, in response to determining that the present location of the drill 902 differs from the target location at 708, a steering mechanism is utilized to adjust the direction of the drill 902 at 710. The direction of the drill 902 may therefore be adjusted based on an identified location or direction.

[0054] In addition, measurement after drilling (MAD) may be carried out to acquire data after the completion of drilling. During MAD, additional data is collected as the drill string is retrieved from the well. The data from MAD
may be utilized to cross-check or validate the data obtained during the drilling operation. The drill string is generally not rotated as the drill string is retrieved from the well, although rotation may be utilized in response to the drill string becoming stuck during retrieval, for example, the drill string may be moved back and forth while rotating in order to free the drill string.

[0055] Advantageously, the location and direction of the drill are determined during drilling, which differs from existing techniques, such as measurement while drilling (MWD). MWD is a non-continuous process in which downhole measurements are first stored and later transmitted to surface, for example, as pressure pulses in the mud system or electro-magnetic (EM) signals.
Thus, the drilling operation continues as the location and direction are determined, reducing or eliminating the time during which drilling is stopped for measurement purposes. By repeatedly determining drill location and direction while drilling continues, the progress of the drilling may be monitored and direction adjustments may be made such that the well generally follows a desired path, with little meandering from the path. In addition, the use of more than one gyroscope increases accuracy of determination of the drill location and direction to increase accuracy of drilling.

[0056] The above-described embodiments are intended to be examples only. Alterations, modifications and variations can be effected to the particular embodiments by those of skill in the art. The scope of the claims should not be limited by the embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole.

Claims (21)

What is claimed is:

1. A method of drilling a wellbore for use in a hydrocarbon recovery operation, the method comprising:
receiving signals from at least two gyroscopes coupled to a drill during drilling of the wellbore, the signals indicative of a change in orientation of the gyroscopes;
analyzing the signals from the gyroscopes to identify a location of the drill relative to a previously identified location;
comparing the location of the drill to a target location of the drill;
in response to determining that the location of the drill differs from the target location, adjusting a direction of the drill based on the identified location of the drill, wherein drilling of the wellbore is continuous during receipt of the signals and analysis of the signals.

2. The method according to claim 1, wherein analyzing the signals comprises determining a distance of the gyroscopes, orientation of the gyroscopes, and depth of the gyroscopes.

3. The method according to claim 1, wherein receiving signals comprises receiving signals from four or more gyroscopes coupled to the drill.

4. The method according to claim 1, wherein analyzing the signals comprises analyzing the signals from the gyroscopes to identify locations, including a location of each of the gyroscopes, and determining an average of the locations.

5. The method according to claim 1, wherein receiving signals comprises repeatedly receiving signals and analyzing comprises repeatedly analyzing to monitor drill location during drilling the wellbore.

6. The method according to claim 1, wherein comparing the location of the drill to a target location comprises comparing a difference between the location of the drill and the target location to a threshold value, and adjusting the direction of the drill comprises adjusting the direction in response to determining that the difference between the location of the drill and the target location exceeds the threshold value.

7. The method according to claim 1, wherein the target location comprises a target zone and the direction of the drill is adjusted in response to determining that the location of the drill is outside the target zone.

8. The method according to claim 1, comprising aggregating signals from the gyroscopes at a processor coupled to the gyroscopes, and transmitting the aggregated signals from the processor to an electronic device at a surface to identify a location of the drill.

9. The method according to claim 8, wherein the aggregated signals are transmitted to the electronic device at the surface via an electromagnetic pulser.

10. An apparatus for drilling a wellbore for use in a hydrocarbon recovery operation, the apparatus comprising:
a drill for creating the wellbore;
a component coupled to the drill;
a drill string coupled to the component; and at least two gyroscopes coupled to the component and in communication with an external electronic device for providing signals to the electronic device during drilling of the wellbore utilizing the drill, the signals indicative of a change in orientation of the gyroscopes, such that the drill is continuously rotatable to continuously drill the wellbore during receipt of the signals and analysis of the signals.

11. The apparatus according to claim 10, comprising the electronic device, wherein the electronic device is configured to analyze the signals from the gyroscopes to identify a location of the drill relative to a previously identified location, compare the location of the drill to a target location of the drill, and determine if the location of the drill differs from a target location.

12. The apparatus according to claim 11, wherein the electronic device is configured to identify the location of the drill by determining a location of each of the gyroscopes and determining an average location of all the gyroscopes.

13. The apparatus according to claim 11, wherein the target location comprises a target zone and the direction of the drill is adjusted in response to determining that the location of the drill is outside the target zone.

14. The apparatus according to claim 10, wherein the at least two gyroscopes comprises at least four gyroscopes coupled to the component.

15. The apparatus according to claim 10, wherein the gyroscopes are housed in the component.

16. The apparatus according to claim 10, comprising one or more of a magnetometer, an inclinometer, or an accelerometer housed in the component and in communication with the external electronic device to provide information utilized for identifying a location of the drill.

17. The apparatus according to claim 10, wherein the at least two gyroscopes are coupled to the electronic device via fiber-optic wires extending from the gyroscopes, through a conduit disposed within the drill string, to a surface.

18. The apparatus according to claim 10, wherein the signals are provided repeatedly to repeatedly monitor a location of the drill.

19. The apparatus according to claim 10, comprising a processor coupled to the gyroscopes for aggregating signals from the gyroscopes, wherein the signals provided to the external electronic device comprise aggregated signals.

20. The apparatus according to claim 19, comprising an electromagnetic pulser for transmitting the aggregated signals by electromagnetic pulses, from the processor to the external electronic device.

21. The apparatus according to claim 10, comprising a steering mechanism for adjusting a direction of the drill to adjust a direction of the wellbore.