WO2011049581A1

WO2011049581A1 - Downhole tool with stabilizer and reamer and related methods

Info

Publication number: WO2011049581A1
Application number: PCT/US2009/061868
Authority: WO
Inventors: Inc. Halliburton Energy Services
Original assignee: Halliburton Energy Services Inc
Priority date: 2009-10-23
Filing date: 2009-10-23
Publication date: 2011-04-28

Abstract

A downhole tool includes a drilling assembly, and a housing coupled with the drilling assembly. The downhole tool further includes a stabilizer including one or more radially extendible pistons, and the stabilizer is associated with the housing. The downhole tool further includes at least one reamer including one or more reaming cutting members, where the one or more reaming cutting members are coupled with the piston of the stabilizer and are radially extendible and axially adjustable.

Description

DOWNHOLE TOOL WITH STABILIZER AND

REAMER AND RELATED METHODS

Technical Field

[0001] The application relates generally to a downhole tool. In particular, the application relates to directional downhole tool with a stabilizer and reamer.

Background

[0002] Directional drilling involves controlling the direction of a wellbore as it is being drilled. Since wellbores are drilled in three dimensional space, the direction of a wellbore includes both its inclination relative to vertical as well as its azimuth. Usually the goal of directional drilling is to reach a target subterranean destination with the drill string.

[0003] It is often necessary to adjust the direction of the wellbore frequently while directional drilling, either to accommodate a planned change in direction or to compensate for unintended and unwanted deflection of the wellbore. Unwanted deflection may result from a variety of factors, including the characteristics of the formation being drilled, the makeup of the bottom hole drilling assembly and the manner in which the wellbore is being drilled. Brief Description of the Drawings

[0004] The embodiments are provided by way of example and not limitation in the figures of the accompanying drawings, in which like references indicate similar elements and in which:

[0005] Figure 1 illustrates a downhole tool with stabilizer and reamer, according to example embodiments.

[0006] Figure 2 illustrates a portion of a downhole tool, according to example embodiments.

[0007] Figure 3 illustrates a downhole tool, according to example

embodiments.

[0008] Figure 4 illustrates an enlarged view of a portion of FIG. 2, according to example embodiments.

[0009] Figure 5 illustrates a portion of the downhole tool showing the reamer in the retracted position.

[0010] Figure 6 illustrates a portion of the downhole tool showing the reamer in the extended position.

[0011] Figure 7 illustrates a block diagram of a portion of a downhole tool, according to example embodiments. Detailed Description

[0012] In the following description of various embodiments, reference is made to the accompanying drawings which form a part hereof, and in which are shown, by way of illustration, specific embodiments which may be practiced. In the drawings, like numerals describe substantially similar components throughout the several views. These embodiments are described in sufficient detail to enable those skilled in the art to practice the present invention. Other embodiments may be utilized and structural, logical, and electrical changes may be made without departing from the scope of the present invention. The following detailed description is not to be taken in a limiting sense, and the scope of the present invention is defined only by the appended claims, along with the full scope of equivalents to which such claims are entitled.

[0013] In various embodiments, a downhole tool includes a drilling assembly, a housing coupled with the drilling assembly, and a stabilizer including an array of radially extendible pistons, where the pistons are disposed in a helical pattern. The downhole tool further includes at least one reamer having one or more reaming cutting members, where the one or more reaming cutting members are coupled with one or more pistons of the stabilizer. In various embodiments, the extendible pistons and reaming cutting members are adjusted axially and/or radially.

[0014] Referring to Figure 1, a downhole tool 100 is shown including an apparatus such as a drill string 108 and a drilling assembly 110. The downhole tool 100 can include a drilling motor for driving a drilling bit, an adjustable gauge stabilizer 120, and at least one reamer 150. The stabilizer 120 includes any device that is coupled with the drilling assembly 110. The downhole drilling assembly 110 includes a housing 112, a fluid passage 114, a power unit 116, a drive assembly, a stabilizer 120, a reamer 150 and a mandrel 118. In an option, the downhole drilling assembly 110 also includes a sensor 190.

[0015] The sensor 190 includes one or more sensors for gathering information about at least one drilling parameter relating to drilling operations or about the environment in which drilling is taking place. This information may relate to drilling parameters such as wellbore inclination, wellbore azimuth, tool face orientation, weight-on-bit, torque, wellbore pressure, wellbore temperature, natural gamma ray emissions, mud cake resistivity and so on. The sensor 190 may gather and store such information for later retrieval, or the sensor 190 may be equipped with a transmitter for transmitting information, for instance to a surface unit. The sensor 190 may also be equipped with a receiver for receiving information. The sensors 190 may be positioned in one location or they may be positioned in various locations to optimize the information gathering process. In an option, the sensor 190 includes a first sensor for detecting a radial position of the reaming cutting members and a second sensor for detecting an axial position of the reaming cutting members. The sensor 190, in a further option, also includes a transmitter 192, a power supply 194, and a processor 196 for processing information received from sensors before the information is transmitted. The components of the sensor 190 may be contained in a single location or they may be positioned at different locations along the drill string 108 or the drilling assembly 110.

[0016] In an option, the transmitter 192 is used to transmit information from the sensor 190 to a surface communication device located above the drilling assembly 110. In an option, the surface communication device is a measurement- while-drilling ("MWD") apparatus. The transmitter 192 may transmit information to the surface communication device in any manner which will preserve the integrity of the information. For instance, the information is transmitted by the transmitter 192 using electrical, magnetic, electromagnetic or acoustic signals.

[0017] The housing 112 is adapted to embody and protect the various components of the assembly 110. The housing 112 includes an upper end portion 111 and a lower end portion 113 and further includes a number of tubular sections connected together with, from example, threaded connections. Some of the sections include, but are not limited to, a dump sub housing, a power unit housing, a transmission unit housing, an upper radial bearing housing, a piston housing, a spring housing, a flow restrictor housing, a sensor crossover housing, a sensor housing, and a bearing housing.

[Q018] The fluid passage 114 extends through the interior of the housing 112 from the upper end portion 111 to the lower end portion 113. The upper end portion 111 of the housing 1 12 is adapted to be coupled with the drill string. For instance, the housing 112 is threaded to allow the assembly 110 to be connected to a drill string 108.

[0019] In an option, a power unit 116 is contained within the power unit housing, and in an option includes a positive displacement downhole motor which converts hydraulic energy derived from circulating fluid into mechamcal energy in the form of a rotating rotor shaft 109. Other types of downhole motors, such as, but not limited to, electric motors, may also be used.

[0020] The drive assembly transmits rotational and thrust energy from the power unit 1 16 to a drilling bit 104 which is connected to the drive assembly when the assembly 1 10 is in use. The drive assembly is rotatable relative to the housing 112.

[0021] The downhole tool further includes a stabilizer 120, where the stabilizer 120 is associated with the piston housing. The stabilizer 120 includes a plurality of pistons 124. At least one reamer 150 is further included. In an option, the reamer 150 includes one or more reaming cutting members 152 disposed on an outer portion or surface of the pistons 124, for example on each of the pistons 124 (See FIG. 4). The reaming cutting members 152 include carbide cylinders, for instance, that are mounted perpendicular to an axis of the downhole tool. In a further option, the downhole tool 100 further includes a pilot reamer 153. [0022] The plurality of pistons 124 extend around an outer periphery of the tool 100, and in an option are disposed in a helical pattern around the tool. In an option, the reaming cutting members 152 progressively extend further along the pistons 124, as shown in Figures 2 and 3. For instance, a first reaming cutting member has a first height, a second reaming cutting member has a second height, and a third reaming cutting member has a third height, where the heights become higher toward the proximal portion of the stabilizer 120. As the downhole tool is rotated and/or progresses deeper into a bore, the progressive cutting structure would begin with a certain level of cutting force, and would progressively increase with the tapered reaming cutting members.

[0023] In an option, the pistons 124 are capable of radial movement relative to the piston housing between a number of different positions, including a retracted position (FIG. 5) and an extended position (FIG. 6). In the retracted position, the outer radial surfaces of the pistons 124 are flush with the exterior of the piston housing and the inner radial surfaces of the pistons 124 extend into the mandrel chamber. In an option, when the pistons 124 are retracted, at least one of the reaming cutting members are flush with the exterior of the piston housing. In the extended position, the outer radial surfaces of the pistons 124 protrude outward from the exterior of the piston housing. In another option, the pistons 124 are also capable of movement into a rest position in which the outer radial surfaces of the pistons 124 are withdrawn slightly inside the exterior of the piston housing. Figure 2 shows the pistons in a retracted position, and Figure 3 shows the pistons the extended position.

[0024] In an option, a radial position of the stabilizer 120 is determined by a stabilizer actuator which is associated with the mandrel 1 18 and which causes radial movement of the stabilizer 120 in response to axial movement of the mandrel 118. In an option, the stabilizer actuator includes a set of ramp rings 122, such as tubular members, having ramped outer surfaces which engage the inner radial surfaces of the pistons 124. The ramp rings 122 are mounted on the mandrel and move axially with the mandrel 118. The ramped outer surfaces of the ramp rings 122 engage the inner radial surfaces of the pistons 124, and the pistons 124 are moved radially outward in response to movement of the mandrel 118 toward the lower end portion 113 of the housing 112.

[0025] In an option the pistons move in an indexed manner. For example, a lower mandrel 117 and its associated components provide an indexing mechanism to facilitate movement of the stabilizer 120 between various positions. For instance, the stabilizer 120 is moved between a retracted position, an extended position and a rest position. In another option, the stabilizer 120 is moved between a retracted position, and an extended position. A tubular barrel cam 113 is rotatably mounted on the lower mandrel 117 and is supported by an upper thrust bearing and a lower thrust bearing. The barrel cam is contained in the mandrel chamber and is capable of rotation relative to the mandrel 118.

[0026] The barrel cam 113 moves in a single direction in a groove, and is prevented from moving in the other direction due to the combined effects of the spring loading of the barrel cam pin 111 and the steps in the groove. The groove is configured so that the barrel cam pin 111 will move in sequence, depending on the number of positions of the pistons, in the groove to a first position, a third position, a second position, the third position, the first position, the third position, the second position, the third position and so on. The groove allows for the pistons to extend radially. In another option, the groove can be configured to allow for the pistons to move axially relative to the downhole tool in addition to, or in alternative to the radial movement.

[0027] A biasing device is provided for urging the mandrel 118. For instance a return spring 164 is provided, and is capable of extension and compression in the spring chamber through a range corresponding at least, to the permitted axial movement of the mandrel 118 between the first position and the second, extended position. The return spring exerts an upward force on the barrel cam nut which tends to move the mandrel 118 toward the upper end portion 111 of the housing 112.

[0028] In an option, the upper mandrel 119 also provides an upper end of the mandrel 118 which communicates with the fluid passage 114 to effect downward axial movement of the mandrel 118 when circulating fluid is circulated through the assembly 110, thus compressing the return spring 164. The lower mandrel 117 defines a balancing piston chamber which contains an annular balancing piston 176.

[0029] A wellbore fluid compartment exposes the balancing piston 176 to the downhole pressure of the wellbore adjacent to the assembly 110. The wellbore fluid compartment is exposed to the downhole pressure of the wellbore, but not the pressure through the interior of the assembly 110. An oil compartment transmits the downhole pressure of the wellbore from the balancing piston 176 to the pistons 124 and cutting reaming members so that only the differential pressure required to overcome the upward force exerted on the mandrel 118 by the return spring 164 will be necessary to move the mandrel 118 toward the lower end portion 113 of the housing 112 and thus extend the pistons.

[0030] In an option, the downhole tool includes a signaling device for signaling whether the mandrel is in the first maximum downward position or in the second maximum downward position, which can be used to determine whether the reaming cutting members are extended or retracted. For instance, the signaling device is a flow restriction device associated with the mandrel and the drive shaft which causes the pressure drop experienced by fluid that passes through the fluid passage to be different, depending upon whether the mandrel is in the first maximum downward position or the second maximum downward position. In an option, the flow restriction device changes the cross sectional area of the fluid passage depending upon the axial position of the mandrel in order to selectively restrict the flow of circulating fluid through the fluid passage. The difference in output pressure at the circulating fluid pump can be sensed from the surface by the drilling crew. The signaling device can be designed and assembled to provide different output pressures for different drilling conditions.

[0031] During use of the downhole tool 100, a borehole is drilled with a drilling assembly, the drilling assembly including a housing and a stabilizer associated with the housing, the stabilizer including adjustable pistons, and reaming cutting members disposed on one or more of the adjustable pistons. The borehole is reamed, in an option, with a pilot reamer, and the borehole is then reamed with reaming cutting members on the pistons. For instance, the reaming is progressive reaming by cutting members having greater height along the downhole tool. The position of the reaming cutting members is modified or adjusted. For example, by radially extending the cutting members, or axially moving the cutting members to the downhole tool. In an option, the radial extension of the piston and the axial location of the piston are modified relative to the drilling assembly based at least in part on a comparison of the determined borehole trajectory and a model of a desired borehole trajectory. In an option, the pistons are moved, for instance, by activating the pistons via pressure. In a further option, the reaming cutting members are cycled in and out with movement of the pistons.

[0032] The stabilizer 120 and reamer 150 can be actuated in a number of different manners. An actuator may be any suitable device capable of axially or radially moving the reaming cutting members of the pistons. For example, an electromechanical actuator or, alternatively, a hydraulic actuator can be used. A power source can be further included for supplying electrical and/or mechanical power to the actuator. In an option, the electrical power may comprise batteries. In one embodiment, a hydraulic supply system may be powered by the batteries to supply hydraulic power to a hydraulically activated actuator.

[0033] In a further option, controller 145 controls the movement of actuator

140 and movement of the reaming cutting members 152. In one example, actuator 140 is a hydraulic cylinder that extends to force the pistons 124 and reaming cutting members 152 radially extend outward toward the wall of borehole 126 (see FIG. 1). When multiple radially extendable reaming cutting members 152 are incorporated, each reaming cutting member 152 may be independently controlled. In addition, each reaming cutting member 152 may be adjusted to any position between a retracted position and a fully extended position. One or more sensors 180 may be incorporated in actuator 140 to measure the displacement of and/or the force applied by each radially extendable reaming cutting member 152. Other radially extendable member alternatives includes a swing arm. For instance, an actuating member is engaged with a swing arm that is pivoted about a pin such that extension of the actuating member forces swing arm outward. Retraction of the actuating member causes swing arm to retract inward. [0034] In another option, the actuator 140 includes a first actuator to radially extend the pistons and a second actuator to axially position the pistons 124. In yet another option, the stabilizer 120 and the reamer 150 are actuated by the difference between the pressure of the circulating fluid being passed downward through the assembly 1 10 and the pressure of the wellbore adjacent to the assembly 110. This pressure differential will be applied to the upper end of the mandrel 118 and will provide a force tending to cause the mandrel 1 18 to move toward the lower end portion 113 of the housing 112. The downward force will be opposed by an upward force exerted on the mandrel 1 18 by the return spring 164. If the downward force is greater than the upward force, the mandrel 118 will move downward relative to the housing.

[0035] If the mandrel 118 moves downward relative to the housing 112, it will move toward either a first maximum downward position in which the pistons 124 are retracted. The barrel cam pin travels in the groove on the barrel cam 113 until it either reaches the first position in the groove which corresponds to the first maximum downward position of the mandrel 118 and retraction of the pistons 124. The pin can travel until it reaches the second position in the groove which corresponds to the second maximum downward position of the mandrel 118 and extension of the pistons and reaming cutting members. In an option, the pistons 124 and cutting members 152 cycle between two positions.

[0036] The downward position of the mandrel 1 18, the pistons 124, and the cutting members 152 can be determined when fluid is being circulated through the assembly 1 10 by observing the output pressure of the circulating fluid pump. If the output pressure is relatively low, the mandrel 1 18 is in the first maximum downward position and the pistons 124 and reaming cutting members 152 are retracted. If the output pressure is relatively high, the mandrel 118 is in the second maximum downward position and the pistons 124 and reaming cutting members 152 are extended. If the reaming cutting members 152 are not in the desired position at any time during drilling operations, the position may be changed by reducing the circulation of fluid through the assembly 110 and then increasing the circulation of fluid through the assembly 110 so that the mandrel 118 can move from one of the maximum downward positions to the maximum upward position and then to the other of the maximum downward positions.

[0037] Figure 4 illustrates a function block diagram of the adjustable stabilizer and reamer. The controller 145 further includes circuits, process, and member in communication with the surface controller 184. The actuator 140 can be done via the surface controller. The signals can be transmitted via electromagnetic wave telemetry, mud pulse telemetry, wire pipe telemetry, acoustic telemetry, or others. In an example, the controller 145 is operatively coupled to a transmitter/receiver 166. In an option, data signals may be transmitted via the transmitter/receiver 166 indicative of a position of the reaming cutting members 152, and instructions may be received to change the position of the reaming cutting members 152.

[0038] For instance, the adjustable stabilizer and reamer includes a navigation sensor 182 to determine a trajectory of the borehole. In an option, a desired well trajectory model may be stored in the memory of the controller 145. Calculated trajectory values from the navigational sensor 182 may be compared to the stored trajectory model and suitable adjustments may be made to the position of extendable reaming cutting members 152 based on the comparison. In an option, navigational sensor data are used downhole to calculate a suggested change in an axial position of the reaming cutting members 152, which the processor 145 can use to change a position of the reaming cutting members 152.

[0039] In the description, numerous specific details such as logic

implementations, opcodes, means to specify operands, resource

partitioning/sharing/duplication implementations, types and interrelationships of system components, and logic partitioning/integration choices are set forth in order to provide a more thorough understanding of the present invention. It will be appreciated, however, by one skilled in the art that embodiments of the invention may be practiced without such specific details. In other instances, control structures, gate level circuits and full software instruction sequences have not been shown in detail in order not to obscure the embodiments of the invention. Those of ordinary skill in the art, with the included descriptions will be able to implement appropriate functionality without undue experimentation.

[0040] References in the specification to "one embodiment", "an

embodiment", "an example embodiment", etc., indicate that the embodiment described may include a particular feature, structure, or characteristic, but every embodiment may not necessarily include the particular feature, structure, or characteristic. Moreover, such phrases are not necessarily referring to the same embodiment. Further, when a particular feature, structure, or characteristic is described in connection with an embodiment, it is submitted that it is within the knowledge of one skilled in the art to affect such feature, structure, or characteristic in connection with other embodiments whether or not explicitly described.

In view of the wide variety of permutations to the embodiments described herein, this detailed description is intended to be illustrative only, and should not be taken as limiting the scope of the invention. What is claimed as the invention, therefore, is all such modifications as may come within the scope of the following claims and equivalents thereto. Therefore, the specification and drawings are to be regarded in an illustrative rather than a restrictive sense.

Claims

What is claimed is:

1. A downhole tool comprising:

a drilling assembly;

a housing coupled with the drilling assembly;

a stabilizer including an array of radially extendible pistons, the pistons disposed in a helical pattern, the stabilizer associated with the housing; and

at least one reamer including one or more reaming cutting members, the one or more reaming cutting members are coupled with one or more pistons of the stabilizer.

2. The downhole tool as recited in claim 1, wherein the reaming cutting member is coupled on each of the pistons.

3. The downhole tool as recited in claim 1, wherein the pistons are pressure activated.

4. The downhole tool as recited in claim 1, wherein the stabilizer includes a plurality of pistons, and reaming cutting members are tapered relative to each other.

5. The downhole tool as recited in claim 1, wherein the pistons are axially adjustable.

6. The downhole tool as recited in claim 1 , further comprising a drilling bit associated with the drilling assembly.

7. The downhole tool as recited in claim 1, further comprising a controller to selectively adjust at least one of the radial extension and an axial position of the pistons.

8. The downhole tool as recited in claim 1, further comprising an actuator to energize the pistons.

9. The downhole tool as recited in claim 8, wherein the actuator is actuated by a hydraulic cylinder.

10. The downhole tool as recited in claim 9, wherein the actuator comprises a first actuator to radially extend the pistons and a second actuator to axially position the pistons.

11. The downhole tool as recited in claim 1 , further comprising a navigation

sensor to determine a trajectory of the borehole.

12. The downhole tool as recited in claim 1, further comprising a controller, where the controller adjusts the radial extension and the axial position of the movable member.

13. The downhole tool as recited in claim 12, further comprising a

transmitter/receiver.

14. The downhole tool as recited in claim 13, wherein the controller adjusts the radial extension and the axial position of the movable member based at least in part on instructions from a surface location received by the

. transmitter/receiver.

15. The downhole tool as recited in claim 1, further comprising a first sensor for detecting a radial position of the reaming cutting members and a second sensor for detecting an axial position of the reaming cutting members.

16. A method comprising:

drilling a borehole with a drilling assembly, the drilling assembly including a housing and a stabilizer associated with the housing, the stabilizer including adjustable pistons, reaming cutting members disposed on one or more of the adjustable pistons;

reaming the borehole with a pilot reamer;

moving the pistons;

reaming the borehole with reaming cutting members on the pistons; and modifying a position of the reaming cutting members.

17. The method as recited in claim 16, wherein adjusting the position of the

reaming cutting members includes radially adjusting the position of the reaming cutting members.

18. The method as recited in claim 16, wherein adjusting the position of the reaming cutting members includes axially adjusting the position of the reaming cutting members.

19. The method as recited in claim 16, wherein moving the pistons includes

activating the pistons via pressure.

20. The method as recited in claim 16, further comprising cycling the reaming cutting members in and out with movement of the pistons.

21. The method as recited in claim 16, wherein reaming includes progressively reaming the borehole with the reaming cutting members.

22. The method as recited in claim 16, further comprising determining a trajectory of the borehole.

23. The method as recited in claim 22, wherein controlling both the radial

extension of the piston and the axial location of the piston relative to the drilling assembly includes adjusting the radial extension and the axial position of the pistons based at least in part on a comparison of the determined borehole trajectory and a model of a desired borehole trajectory.