Patent Application
20170145761
During subterranean drilling and completion operations, a pipe or other conduit is lowered into a borehole in an earth formation during or after drilling operations. Such pipes are generally configured as multiple pipe segments to form a “string”, such as a drill string or production string. As the string is lowered into the borehole, additional pipe segments are coupled to the string by various connection mechanisms, such as threaded couplings. Such coupling is referred to as “make up”. During make up, stabbing guides are used to aid human workers in aligning pin to box threads and preventing face damage and connection failure.
An iron roughneck is a piece of hydraulic machinery used to automatically connect and disconnect segments of pipe in a modern drilling operation. In more detail, an iron roughneck allows for pipe segments to be manipulated as they are hoisted into and out of a borehole without having a human directly manipulating the segments. Such iron roughnecks may be controlled by external controllers. One issue, however, that may still require human intervention is that while automatic, the roughnecks may not be adept at aligning the segments such that face damage does not occur.
Various power and/or communication signals may be transmitted through the pipe segments via a “wired pipe” configuration. Such configurations include electrical, optical or other conductors extending along the length of selected pipe segments or string segments. The conductors are operably connected between pipe segments by a variety of configurations.
One such configuration includes a threaded male-female configuration often referred to as a pin-box connection. The pin box connection includes a male member, i.e., a “pin end” that includes an exterior threaded portion, and a female member, i.e., a “box end”, that includes an interior threaded portion and is configured to receive the pin in a threaded connection.
Some wired pipe configurations include a transmission device mounted on the tip of the pin end as well as in the box end. The transmission device, or “coupler,” can transmit power, data or both to an adjacent coupler. The coupler in the pin end is typically connected via a coaxial cable or other means to the coupler in the box end.
Disclosed herein is a wired pipe joining system for joining wired pipe segments having first end, a second end, a first coupler in the first end, a second coupler in the second end, and a transmission medium in communication with the first and second couplers. The system includes a lower clamp configured to hold a top pipe segment and a top rotation arm to guide a first end of a new pipe segment into a second end of a top pipe segment. The system also includes a top coupler measurement device configured to connect to a second end of the new pipe segment and receive a signal from a second coupler in the second end of the new pipe segment and a controller that causes the top rotation arm to move the new pipe segment to cause the signal received by the top coupler measurement to be maximized.
Also disclosed is a method of joining wired pipe segments having first end, a second end, a first coupler in the first end, a second coupler in the second end, and a transmission medium in communication with the first and second couplers. The method includes: placing a top pipe segment into a lower clamp of a pipe joining device; placing a new pipe segment into a top rotation arm of the pipe joining device; causing a signal to be presented on a second coupler of the top pipe segment; determining an amplitude of the signal as received by a top coupler measurement device coupled to a second end of the new pipe segment; moving the new pipe segment to maximize the amplitude; and rotating the new pipe segment to join it to the top pipe segment.
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 system, apparatus and method are presented herein by way of exemplification and not limitation with reference to the Figures.
Referring to
For example, during drilling operations, drilling fluid or drilling “mud” is introduced into the string 12 from a source such as a mud tank or “pit” and is circulated under pressure through the string 12, for example via one or more mud pumps. The drilling fluid passes into the string 12 and is discharged at the bottom of the borehole through openings in a drill bit located at the downhole end of the string 12. The drilling fluid flows up between the string 12 and the borehole wall and is discharged into the mud tank or other location.
The string 12 may include at least one wired pipe segment 14 having an uphole end 18 and a downhole end 16. As described herein, “uphole” refers to a position that is above another location and “downhole” refers to a location below another location. It shall be understood that the uphole end 18 could be below the downhole end 16 without departing from the scope of the disclosure herein.
At least an inner bore or other conduit 20 extends along the length of each segment 14 to allow drilling mud or other fluids to flow therethrough. A transmission line 22 is located within the wired segment 14. In one embodiment, the transmission line 22 is a coaxial cable. In another embodiment, the transmission line 22 is formed of any manner of carrying power or data, including, for example, a twisted pair. In the case where the transmission line 22 is a coaxial cable it may include an inner conductor surrounded by a dielectric material. The coaxial cable may also include a shield layer that surrounds the dielectric material. In one embodiment, the shield layer is electrically coupled to an outer conductor that may be formed, for example, by a rigid or semi-rigid tube of a conductive material.
The segment 14 includes a downhole connection 24 and an uphole connection 26. The segment 14 is configured so that the uphole connection 26 is positioned at an uphole location relative to the downhole connection 24. The downhole connection 24 includes a male connection portion 28 having an exterior threaded section, and is referred to herein as a “pin end” 24. The uphole connection 26 includes a female connection portion 30 having an interior threaded section, and is referred to herein as a “box end” 26.
The pin end 24 and the box end 26 are configured so that the pin end 24 of one wired pipe segment 14 can be disposed within the box end 26 of another wired pipe segment 14 to effect a fixed connection therebetween to connect the segment 14 with another adjacent segment 14 or other downhole component. In one embodiment, the exterior of the male connection portion 28 and the interior of the female connection portion 30 are tapered. Although the pin end 24 and the box end 26 are described has having threaded portions, the pin end 24 and the box end 26 may be configured to be coupled using any suitable mechanism, such as bolts or screws or an interference fit.
In one embodiment, the system 10 is operably connected to a downhole or surface processing unit which may act to control various components of the system 10, such as drilling, logging and production components or subs. Other components include machinery to raise or lower segments 14 and operably couple segments 14, and transmission devices. The downhole or surface processing unit may also collect and process data generated by the system 10 during drilling, production or other operations.
As described herein, “drillstring” or “string” refers to any structure or carrier suitable for lowering a tool through a borehole or connecting a drill bit to the surface, and is not limited to the structure and configuration described herein. For example, a string could be configured as a drillstring, hydrocarbon production string or formation evaluation string. The term “carrier” as used herein means any device, device component, combination of devices, media and/or member that may be used to convey, house, support or otherwise facilitate the use of another device, device component, combination of devices, media and/or member. Exemplary non-limiting carriers include drill strings of the coiled tube type, of the jointed pipe type and any combination or portion thereof. Other carrier examples include casing pipes, wirelines, wireline sondes, slickline sondes, drop shots, downhole subs, BHA's and drill strings.
Referring to
It shall be understood that the transmission device 34 could also be included in a repeater element 50 disposed between adjacent segments 14 (e.g, within the box end) as shown
As illustrated in
Regardless of the configuration, it shall be understood that each transmission device 34 can be connected to one or more transmission lines 22. Embodiments disclosed herein are directed to how the transmission lines 22 can be formed and disposed in a segment 14. In one embodiment, the transmission line 22 is capable of withstanding the tensile, compression and torsional stresses and superimposed dynamic accelerations typically present in downhole tools when exploring oil, gas or geothermal wells.
In one embodiment, the transmission line 22 includes a wire channel (e.g., an outer protective layer) and a transmission element. The transmission element can be selected from one of coaxial cable, twisted pair wires, and individual wires. The following description is presented with respect to coaxial wire but it shall be understood that the teachings herein are applicable to any type of transmission element.
As shown in
In practice, pipe joining (and unjoining) devices are commonly referred to as iron roughnecks and may be referred as such from time to time herein. In general, iron roughnecks use a rotary table and torque wrench(es) to make up or break down a drill string. As illustrated, the joining device 500 includes a lower clamp 511 that clamps the top segment 14a and a top rotation arm 512 that rotates pipe segment 14c to either join it to top segment 14a or to remove it from the top segment 14a.
The following description relates to adding segments to the drill string 502. In general, known pipe joining devices (e.g., iron roughnecks) work for their intended purposes. In some instances, the top rotation arm 512 may include the ability to move the end bottom end of the new segment 14c in one or both the x and y directions (see
Herein, either the BHA 504 or a repeater 50 (
Set forth below are some embodiments of the foregoing disclosure:
Embodiment 1: A wired pipe joining system for joining wired pipe segments having first end, a second end, a first coupler in the first end, a second coupler in the second end, and a transmission medium in communication with the first and second couplers, the system comprising: a lower clamp configured to hold a top pipe segment; a top rotation arm to guide a first end of a new pipe segment into a second end of a top pipe segment; a top coupler measurement device configured to connect to a second end of the new pipe segment and receive a signal from a second coupler in the second end of the new pipe segment; a controller that causes the top rotation arm to move the new pipe segment to cause the signal received by the top coupler measurement to be maximized.
Embodiment 2: The wired pipe joining system of embodiment 1, wherein the second coupler is in a repeater in a box end of the new pipe segment.
Embodiment 3: The wired pipe joining system of embodiment 1, wherein the signal received from the second coupler is generated by a repeater in the top pipe segment.
Embodiment 4: The wired pipe joining system of embodiment 1, wherein the signal received from the second coupler is generated by a bottom hole assembly.
Embodiment 5: The wired pipe system of embodiment 1, wherein at least one of the first and second couplers in the top pipe segment is an inductive coupler.
Embodiment 6: The wired pipe system of embodiment 1, wherein at least one of the first and second couplers in the top pipe segment is a resonant coupler.
Embodiment 7: A method of joining wired pipe segments having first end, a second end, a first coupler in the first end, a second coupler in the second end, and a transmission medium in communication with the first and second couplers, the method comprising: placing a top pipe segment into a lower clamp of a pipe joining device; placing a new pipe segment into a top rotation arm of the pipe joining device; causing a signal to be presented on a second coupler of the top pipe segment; determining an amplitude of the signal as received by a top coupler measurement device coupled to a second end of the new pipe segment; moving the new pipe segment to maximize the amplitude; and rotating the new pipe segment to join it to the top pipe segment.
Embodiment 8: The method of embodiment 7, wherein the signal received by the top coupler measurement device is generated by a repeater in the top pipe segment.
Embodiment 9: The method of embodiment 7, wherein the signal received by the top coupler measurement device is generated by a bottom hole assembly.
Embodiment 10: The method of embodiment 7, wherein at least one of the first and second couplers in the top pipe segment is an inductive coupler.
Embodiment 11: The method of embodiment 7, wherein at least one of the first and second couplers in the top pipe segment is a resonant coupler.
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 further 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.
