Patent Application
20200300061
In the resource recovery industry, the drilling of lateral boreholes from a primary borehole is increasingly utilized to increase production from resource bearing formations. Some systems for drilling lateral boreholes utilize whipstocks, which divert the direction of a drill string in a direction lateral to the primary borehole. Typically the angle and length of the whipstock dictates the borehole length needed to drill an initial portion of a lateral well (rathole) and establish an exit from the primary borehole.
An embodiment of an apparatus for drilling a secondary borehole includes a whipstock assembly configured to be deployed in a primary borehole, the whipstock assembly including a whipstock ramp, and a drilling assembly connected to a borehole string, the drilling assembly including a drill bit connected to an articulated string portion having a plurality of connected sections configured to move laterally with respect to one another. The articulated string portion is configured to be diverted by the whipstock ramp in a lateral direction to initiate drilling of a secondary borehole from the primary borehole.
An embodiment of a method of drilling a secondary borehole includes deploying a whipstock assembly in a primary borehole, the whipstock assembly including a whipstock ramp, and deploying a borehole string including a drilling assembly in the primary borehole, the drilling assembly including a drill bit connected to an articulated string portion. The articulated string portion has a plurality of connected sections configured to move laterally with respect to one another. The method also includes rotating the drill bit and advancing the drilling assembly along the whipstock assembly, and diverting the drill bit and the articulated string portion in a lateral direction by the whipstock ramp to initiate drilling of a secondary borehole from the primary borehole.
The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:
A detailed description of one or more embodiments of the disclosed systems and methods are presented herein by way of exemplification and not limitation with reference to the Figures.
Methods, systems and apparatuses are provided herein for drilling or otherwise forming a secondary (lateral) borehole that extends from a primary borehole. An embodiment of a drilling system includes a drill string having an articulated string portion that permits the drill string to be directed in a lateral direction to initiate a secondary borehole and/or drill a length of the secondary borehole. In one embodiment, the drilling system includes a whipstock assembly for directing the drilling assembly and the articulated string portion in a lateral direction to initiate the secondary borehole.
Embodiments described herein provide a number of advantages. For example, typical whipstock sidetracking operations require a relatively long length of the primary borehole to initiate and drill a secondary borehole. The articulated string portion and whipstock described herein allow for the drill string to initiate the secondary borehole (e.g., turn from a vertical or near vertical to a horizontal direction) using a smaller length of the primary borehole. This allows for more secondary boreholes to be drilled from a primary borehole and provides for quicker exit.
The ability to more quickly drill a secondary borehole and drill the secondary borehole using a smaller length of the primary borehole is useful for a variety of applications, including drilling in a geothermal environment. For example, multiple laterals can be drilled within a fracture zone in a single trip, as the drilling assembly can be retracted from a secondary borehole and used to drill additional secondary boreholes without having to remove the drilling assembly to the surface.
Referring to
A surface structure or surface equipment includes or is connected to various components such as drill rig 18. The drill rig 18 may include a wellhead, derrick and/or rotary table for performing various functions, such as supporting the borehole string 12, deploying the borehole string 12 into the borehole 14, rotating the borehole string 12, circulating fluid, communicating with downhole components, performing surface measurements and/or performing downhole measurements. In one embodiment, the borehole string 12 is a drill string including one or more pipe sections that extend into the borehole 14. The borehole string 12 is not so limited and may be constituted of different components, such as coiled tubing.
In one embodiment, the system 10 includes a drilling apparatus or assembly 20 configured to be controlled to form an initial length (sometimes referred to as a “rathole”) of a secondary borehole extending from the borehole 12. One or more components of the drilling assembly 20 can be configured as a bottomhole assembly (BHA). The drilling assembly 12 may also be used to drill subsequent lengths of the secondary borehole. Operations that include forming ratholes and/or secondary boreholes are referred to herein as sidetracking operations. The borehole 12 in such an embodiment is referred to herein as a primary borehole or pilot borehole.
The drilling assembly 20 includes a drill bit 22 connected to the borehole string 12. In one embodiment, the drilling assembly includes a downhole drilling motor 24 such as a mud motor 24. The drilling assembly 20 may include other components, such as drill collars, stabilizers, steering components and/or sensors for measuring downhole conditions (e.g., pressure, temperature, flow rate and others).
The system 10 is not limited to use with a drilling assembly and/or drill bit. For example, the system 10 may instead use a milling assembly having, e.g., a lead mill and one or more following mills such as watermelon mills. Milling assemblies can be used, for example, to initiate a secondary borehole through casing.
The drilling assembly 20 and/or the borehole string 12 also includes an articulated string portion 26 having one or more joints 28 that connect string sections 30. The articulated string portion 26 allows the drilling assembly 20 to be directed away from the borehole 12 along a relatively short length of the borehole 14 (e.g., less than about 100 feet). This is advantageous in high temperature and pressure environments such as geothermal environments.
In the embodiment of
An embodiment of the articulated string portion 26 is shown in
Relative sizes and shapes of the male portions 34 and the female portions 38 are selected so that there is a gap therebetween. The gap between the male portion 34 and the female portion 38 of adjacent string sections 30 permits a first string section 30 to move laterally relative to an adjacent second string section 30. Lateral movement may include radial movement and/or angular movement in a direction orthogonal to a longitudinal axis of the borehole 14, the borehole string 12 and/or the second string section. For example, movement directions are shown in
The male portions 34 and the female portions 38 may have any suitable shape, and each end may have any suitable number of male portions and/or female portions. For example, in the string section 30 of
Each string section 30 includes features configured to prevent flow of fluid from the central fluid conduit through gaps between interlocking ends. For example, a deformable compression seal can be fit into the gaps to allow relative movement of adjacent string sections 30 while preventing fluid flow into the borehole annulus. Other examples include o-rings and/or an inner liner or sleeve, such as a rubber inner liner.
The joints 28 are not limited to the configuration and type discussed above, as the joints may be any type of joint that permits relative lateral movement between string sections 30. For example, the joints 28 may be ball joints or universal joints of any kind. Another example of a joint 28 is a constant-velocity (CV) joint.
In one embodiment, the articulated string portion 30 is configured as a drill collar, and each section 30 is a length of a drill collar. Drill collars typically have thicker walls than other parts of the drill string (e.g., pipe sections) and are provided to add weight to the drilling assembly 20.
The articulated string portion 26 may be connected to components of the drilling assembly 20 in any suitable manner. For example, as shown in
The system 10 of
The system 10, in one embodiment, includes a whipstock assembly 42 having a whipstock 44 that is deployed in the primary borehole 12 to a selected location corresponding to the location at which a secondary borehole is to be drilled. The whipstock 44 includes a whipstock ramp 46 that acts to guide the drilling assembly 12 when performing a sidetracking operation. The whipstock ramp 46 may have a straight slope as shown in
Referring to
The whipstock assembly 42 is not limited to the assembly shown in
It is noted that terms such as “upper,” “lower,” “upward”, “downward,” “uphole” and “downhole” are used herein to describe relative positions of various components. Such terms are used to denote relative positions of components along a borehole with respect to a surface end of the borehole, which may or may not correspond to vertical depth locations, as the borehole 12 and/or secondary boreholes may not be vertical. For example, the borehole 12 and secondary boreholes can have deviated and/or horizontal sections. Thus, for example, an upper location refers to a location that is closer to the surface along the path of the borehole than a reference location; as the path may be deviated, horizontal or directed toward the surface, the upper location may be at the same or similar vertical depth, or even below the reference location.
Referring again to
Surface and/or downhole sensors or measurement devices may be included in the system 10 for measuring and monitoring aspects of an operation, fluid properties, component characteristics and others. For example, the system 10 includes fluid pressure and/or flow rate sensors 64 and 66 for measuring fluid flow into and out of the borehole 12, respectively. Fluid flow characteristics may also be measured downhole, e.g., via fluid flow rate and/or pressure sensors in the borehole string 12.
The borehole string 12 may include additional tools and/or sensors for measuring various properties and conditions. For example, the borehole string 12 includes a LWD or MWD measurement tool 68 that has one or more sensors or sensing devices 70 for detecting and/or analyzing formation measurements, such as resistivity, seismic, acoustic, gamma ray, and/or nuclear measurements. The one or more sensing devices 70 can be configured to measure borehole conditions (e.g., temperature, flow rate, pressure, chemical composition and others) and/or tool conditions (vibration, wear, strain, stress, orientation, location and others).
In one embodiment, one or more downhole components and/or one or more surface components are in communication with and/or controlled by a processor such as a downhole processor 72 and/or a surface processing unit 74. In one embodiment, the surface processing unit 74 is configured as a surface control unit which controls various parameters such as rotary speed, weight-on-bit, fluid flow parameters (e.g., pressure and flow rate) and others.
In this embodiment, the drilling assembly 20 includes a non-rotating sleeve or housing 78 that surrounds all or part of the articulated string portion 26. In this context, “non-rotating” refers to not being rotated directly by the top drive or rotated with the drill string; the sleeve 78 in some instances may rotate at a lower rate than the drill string.
The sleeve 78, in one embodiment, is a curved sleeve that forms a flexible curved guide through which the articulated string section 26 extends to the drill bit 22. The curved sleeve 78 is flexible so that the sleeve 78 is forced into a straight path as the sleeve 78 is deployed through the primary borehole 12. To facilitate keeping the sleeve 78 straight during deployment, one or more laterally extendable members such as guide pads 80 may be incorporated into the sleeve. The guide pads can be operated using, e.g., the surface processing unit 74 via a communication cable or wired pipe.
The sleeve 78 may be mounted on the articulated string section 26 by an upper bearing assembly 82 and a lower bearing assembly 84. A clutch sub 86 or other suitable mechanism may be connected to the articulated string section 26 and actuated to engage the string section 26, e.g., to change an orientation of the sleeve 78. In one embodiment, a shock sub 88 is disposed between the articulated string section 26 and the drill bit 22 to reduce shock and vibration on the drill bit 22 and the drilling assembly as the secondary borehole 76 is initiated and/or drilled.
The drilling assembly as shown in
The method 100 includes one or more of stages 101-105 described herein. In one embodiment, the method 100 includes the execution of all of stages 101-105 in the order described. However, certain stages 101-105 may be omitted, stages may be added, or the order of the stages changed.
In the first stage 101, the whipstock assembly 42 is deployed into a primary borehole 12. The whipstock assembly is deployed by, e.g., the support string 50, until the whipstock assembly 42 reaches a selected location.
In the second stage 102, a borehole string 12 and a drilling assembly 20 is deployed into the primary borehole 12. The drilling assembly 20 includes an articulated drill string section 30 and a drill bit 22. The drilling assembly 20 is deployed until the drill bit 22 reaches the whipstock ramp 46.
In the third stage 103, fluid is circulated through the borehole string 12 and the drill bit is operated, e.g., by a mud motor 24 or by a top drive.
In the fourth stage 104, as the drill bit 22 is rotated, the drilling assembly 20 is advanced along the whipstock ramp 46 and an initial length of the secondary borehole 76 is initiated. The articulated string portion 26 may be directed primarily by the whipstock 44, or an additional steering mechanism may be included. For example, the drilling assembly 20 can include a curved sleeve 78 that acts in addition to the whipstock to direct the articulated string portion 26 to a deviated or horizontal direction.
Once the initial length of the secondary borehole 76 is formed, the drilling assembly 20 can continue to advance to drill a selected length of the secondary borehole 76.
In the fifth stage 105, the drilling assembly 20 is retracted from the secondary borehole 76 and a subsequent operation is performed. For example, the whipstock 44 and/or the drilling assembly 20 can be moved to a different location and/or re-oriented to drill another secondary borehole. Other subsequent operations include, e.g., stimulation, completion and production operations.
It is noted that the method 100 can include various other functions. For example, sensors such as the pressure and/or flow rate sensors 64 and 66 can be used to monitor pressure and/or flow rate during the above stages. In addition, various other measurements can be performed, e.g., via one or more LWD tools, to evaluate the formation and/or monitor conditions of fluid in the borehole and/or operation of downhole components.
Aspects of the method 100 can be repeated to drill multiple secondary or lateral boreholes. As the length required for drilling a secondary borehole is less than conventional sidetracking operations, the method 100 allows for drilling more secondary boreholes than conventional sidetracking systems, which can improve productivity by, e.g., exposing more fractures in the formation.
Set forth below are some embodiments of the foregoing disclosure:
Embodiment 1: An apparatus for drilling a secondary borehole, the apparatus comprising: a whipstock assembly configured to be deployed in a primary borehole, the whipstock assembly including a whipstock ramp; a drilling assembly connected to a borehole string, the drilling assembly including a drill bit connected to an articulated string portion having a plurality of connected sections configured to move laterally with respect to one another, wherein the articulated string portion is configured to be diverted by the whipstock ramp in a lateral direction to initiate drilling of a secondary borehole from the primary borehole.
Embodiment 2: The apparatus as in any prior embodiment, wherein the plurality of connected sections includes a first section and an adjacent second section connected by a joint configured to permit the first section to be oriented laterally relative to the second section.
Embodiment 3: The apparatus as in any prior embodiment, wherein the joint is formed by a wall of the first section having a shape configured as a male portion, and a wall of the second section having a shape configured as a female portion, the male portion configured to fit into the female portion to connect the first section to the second section.
Embodiment 4: The apparatus as in any prior embodiment, wherein the male portion and the female portion are configured to form a gap therebetween, the gap permitting the male portion to be oriented laterally relative to the female portion.
Embodiment 5: The apparatus as in any prior embodiment, further comprising a fluid displacement motor disposed between the articulated string portion and the drill bit.
Embodiment 6: The apparatus as in any prior embodiment, wherein the drilling assembly and the articulated string portion are configured to be rotated from a surface location.
Embodiment 7: The apparatus as in any prior embodiment, further comprising a shock absorbing assembly disposed between the articulated string portion and the drill bit.
Embodiment 8: The apparatus as in any prior embodiment, further comprising a curved sleeve surrounding at least part of the articulated string portion, the curved sleeve configured to direct the articulated string portion laterally as the articulated string portion is advanced along the whipstock assembly.
Embodiment 9: The apparatus as in any prior embodiment, wherein the non-rotating sleeve includes one or more extendable members configured to be actuated to engage a surface of the borehole to change a direction of the drilling assembly.
Embodiment 10: The apparatus as in any prior embodiment, further comprising a processing device configured to control an operational parameter of the drill string.
Embodiment 11: A method of drilling a secondary borehole, the method comprising: deploying a whipstock assembly in a primary borehole, the whipstock assembly including a whipstock ramp; deploying a borehole string including a drilling assembly in the primary borehole, the drilling assembly including a drill bit connected to an articulated string portion, the articulated string portion having a plurality of connected sections configured to move laterally with respect to one another; rotating the drill bit and advancing the drilling assembly along the whipstock assembly; and diverting the drill bit and the articulated string portion in a lateral direction by the whipstock ramp to initiate drilling of a secondary borehole from the primary borehole.
Embodiment 12: The method as in any prior embodiment, wherein the plurality of connected sections includes a first section and an adjacent second section connected by a joint configured to permit the first section to be oriented laterally relative to the second section.
Embodiment 13: The method as in any prior embodiment, wherein the joint is formed by a wall of the first section having a shape configured as a male portion, and a wall of the second section having a shape configured as a female portion, the male portion configured to fit into the female portion to connect the first section to the second section.
Embodiment 14: The method as in any prior embodiment, wherein the male portion and the female portion are configured to form a gap therebetween when connected, the gap permitting the male portion to be oriented laterally relative to the female portion.
Embodiment 15: The method as in any prior embodiment, wherein the drill bit is rotated by a fluid displacement motor disposed between the articulated string portion and the drill bit.
Embodiment 16: The method as in any prior embodiment, wherein the drill bit is rotated by rotating the drilling assembly and the articulated string portion from a surface location.
Embodiment 17: The method as in any prior embodiment, wherein the drilling assembly includes a shock absorbing assembly disposed between the articulated string portion and the drill bit.
Embodiment 18: The method as in any prior embodiment, wherein the drilling assembly includes a curved sleeve surrounding at least part of the articulated string portion, the curved sleeve configured to direct the articulated string portion laterally as the articulated string portion is advanced along the whipstock assembly.
Embodiment 19: The method as in any prior embodiment, wherein the non-rotating sleeve includes one or more extendable members configured to be actuated to engage a surface of the borehole to change a direction of the drilling assembly.
Embodiment 20: The method as in any prior embodiment—wherein one or more aspects of the method are performed by controlling an operational parameter of the drill string by a processing device.
The use of the terms “a” and “an” and “the” and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should be noted that the terms “first,” “second,” and the like herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The modifier “about” used in connection with a quantity is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the particular quantity).
The teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a wellbore, and/or equipment in the wellbore, such as production tubing. The treatment agents may be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc.
While the invention has been described with reference to an exemplary embodiment or embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the claims. Also, in the drawings and the description, there have been disclosed exemplary embodiments of the invention and, although specific terms may have been employed, they are unless otherwise stated used in a generic and descriptive sense only and not for purposes of limitation, the scope of the invention therefore not being so limited.
