Abstract:
In one aspect, an apparatus for use downhole is disclosed that in one configuration includes a downhole device configured to be in an active position and an inactive position and an actuation device that includes: a housing including an annular chamber configured to house a first fluid therein, a piston in the annular chamber configured to divide the annular chamber into a first section and a second section, the piston being coupled to a biasing member, a control unit configured to enable movement of the first fluid from the first section to the second section to supply a second fluid under pressure to the tool to move the tool into the active position and from the second section to the first section to stop the supply of the second fluid to the tool to cause the tool to move into the inactive position. In another aspect, the apparatus includes a telemetry unit that sends a first pattern recognition signal to the control unit to move the tool in the active position and a second pattern recognition signal to move the tool in the inactive position.

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
       [0001]    This application takes priority from U.S. Provisional application Ser. No. 61/377,146, filed on Aug. 26, 2010, which is incorporated herein in its entirety by reference. 
     
    
     BACKGROUND 
       [0002]    1. Field of the Disclosure 
         [0003]    This disclosure relates generally to downhole tools that may be actuated from a remote location, such as the surface. 
         [0004]    2. Background of the Art 
         [0005]    Oil wells (also referred to as wellbores or boreholes) are drilled with a drill string that includes a tubular member (also referred to as a drilling tubular) having a drilling assembly (also referred to as the drilling assembly or bottomhole assembly or “BHA”) which includes a drill bit attached to the bottom end thereof. The drill bit is rotated to disintegrate the rock formation to drill the wellbore. The drill string often includes tools or devices that need to be remotely activated and deactivated during drilling operations. Such devices include, among other things, reamers, stabilizer or force application members used for steering the drill bit, Production wells include devices, such as valves, inflow control device, etc. that are remotely controlled. The disclosure herein provides a novel apparatus for controlling such and other downhole tools or devices. 
       SUMMARY 
       [0006]    In one aspect, an apparatus for use downhole is disclosed that in one configuration includes a downhole tool configured to be in an active position and an inactive position and an actuation device that includes: a housing including an annular chamber configured to house a first fluid therein, a piston in the annular chamber configured to divide the annular chamber into a first section and a second section, the piston being coupled to a biasing member, a control unit configured to move the first fluid from the first section to the second section to supply a second fluid under pressure to the tool to move the tool into the active position and from the second section to the first section to stop the supply of the second fluid to the tool to cause the tool to move into the inactive position. In another aspect, the apparatus includes a telemetry unit that sends a first pattern recognition signal to the control unit to move the tool in the active position and a second pattern recognition signal to move the tool in the inactive position. 
         [0007]    The disclosure provides examples of various features of the apparatus and method disclosed herein are summarized rather broadly in order that the detailed description thereof that follows may be better understood. There are, of course, additional features of the apparatus and method disclosed hereinafter that will form the subject of the claims appended hereto. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0008]    The disclosure herein is best understood with reference to the accompanying figures in which like numerals have generally been assigned to like elements and in which: 
           [0009]      FIG. 1  is an elevation view of a drilling system including an actuation device, according to an embodiment of the present disclosure; 
           [0010]      FIGS. 2A and 2B  are sectional side views of an embodiment a portion of a drill string, a tool and an actuation device, wherein the tool is depicted in two positions, according to an embodiment of the present disclosure; and 
           [0011]      FIGS. 3A and 3B  are sectional schematic views of an actuation device in two states or positions, according to an embodiment of the present disclosure. 
       
    
    
     DETAILED DESCRIPTION OF THE EMBODIMENTS 
       [0012]      FIG. 1  is a schematic diagram of an exemplary drilling system  100  that includes a drill string having a drilling assembly attached to its bottom end that includes a steering unit according to one embodiment of the disclosure.  FIG. 1  shows a drill string  120  that includes a drilling assembly or bottomhole assembly (“BHA”)  190  conveyed in a borehole  126 . The drilling system  100  includes a conventional derrick  111  erected on a platform or floor  112  which supports a rotary table  114  that is rotated by a prime mover, such as an electric motor (not shown), at a desired rotational speed. A tubing (such as jointed drill pipe)  122 , having the drilling assembly  190  attached at its bottom end extends from the surface to the bottom  151  of the borehole  126 . A drill bit  150 , attached to drilling assembly  190 , disintegrates the geological formations when it is rotated to drill the borehole  126 . The drill string  120  is coupled to a draw works  130  via a Kelly joint  121 , swivel  128  and line  129  through a pulley. Draw works  130  is operated to control the weight on bit (“WOB”). The drill string  120  may be rotated by a top drive (not shown) instead of by the prime mover and the rotary table  114 . The operation of the draw works  130  is known in the art and is thus not described in detail herein. 
         [0013]    In an aspect, a suitable drilling fluid  131  (also referred to as “mud”) from a source  132  thereof, such as a mud pit, is circulated under pressure through the drill string  120  by a mud pump  134 . The drilling fluid  131  passes from the mud pump  134  into the drill string  120  via a de-surger  136  and the fluid line  138 . The drilling fluid  131   a  from the drilling tubular discharges at the borehole bottom  151  through openings in the drill bit  150 . The returning drilling fluid  131   b  circulates uphole through the annular space  127  between the drill string  120  and the borehole  126  and returns to the mud pit  132  via a return line  135  and drill cutting screen  185  that removes the drill cuttings  186  from the returning drilling fluid  131   b . A sensor S 1  in line  138  provides information about the fluid flow rate. A surface torque sensor S 2  and a sensor S 3  associated with the drill string  120  provide information about the torque and the rotational speed of the drill string  120 . Rate of penetration of the drill string  120  may be determined from the sensor S 5 , while the sensor S 6  may provide the hook load of the drill string  120 . 
         [0014]    In some applications, the drill bit  150  is rotated by rotating the drill pipe  122 . However, in other applications, a downhole motor  155  (mud motor) disposed in the drilling assembly  190  also rotates the drill bit  150 . In embodiments, the rotational speed of the drill string  120  is powered by both surface equipment and the downhole motor  155 . The rate of penetration (“ROP”) for a given drill bit and BHA largely depends on the WOB or the thrust force on the drill bit  150  and its rotational speed. 
         [0015]    With continued reference to  FIG. 1 , a surface control unit or controller  140  receives signals from the downhole sensors and devices via a sensor  143  placed in the fluid line  138  and signals from sensors S 1 -S 6  and other sensors used in the system  100  and processes such signals according to programmed instructions provided from a program to the surface control unit  140 . The surface control unit  140  displays desired drilling parameters and other information on a display/monitor  142  that is utilized by an operator to control the drilling operations. The surface control unit  140  may be a computer-based unit that may include a processor  142  (such as a microprocessor), a storage device  144 , such as a solid-state memory, tape or hard disc, and one or more computer programs  146  in the storage device  144  that are accessible to the processor  142  for executing instructions contained in such programs. The surface control unit  140  may further communicate with at least one remote control unit  148  located at another surface location. The surface control unit  140  may process data relating to the drilling operations, data from the sensors and devices on the surface, data received from downhole and may control one or more operations of the downhole and surface devices. 
         [0016]    The drilling assembly  190  also contains formation evaluation sensors or devices (also referred to as measurement-while-drilling, “MWD,” or logging-while-drilling, “LWD,” sensors) determining resistivity, density, porosity, permeability, acoustic properties, nuclear-magnetic resonance properties, corrosive properties of the fluids or formation downhole, salt or saline content, and other selected properties of the formation  195  surrounding the drilling assembly  190 . Such sensors are generally known in the art and for convenience are generally denoted herein by numeral  165 . The drilling assembly  190  may further include a variety of other sensors and communication devices  159  for controlling and/or determining one or more functions and properties of the drilling assembly (such as velocity, vibration, bending moment, acceleration, oscillations, whirl, stick-slip, etc.) and drilling operating parameters, such as weight-on-bit, fluid flow rate, pressure, temperature, rate of penetration, azimuth, tool face, drill bit rotation, etc. 
         [0017]    Still referring to  FIG. 1 , the drill string  120  further includes one or more downhole tools  160   a  and  160   b . In an aspect, the tool  160   a  is located in the BHA  190 , and includes at least one reamer  180   a  to enlarge a wellbore  126  diameter as the BHA  190  penetrates the formation  195 . In addition, the tool  160   b  may be positioned uphole of and coupled to the BHA  190 , wherein the tool  160   b  includes a reamer  180   b . In one embodiment, each reamer  180   a ,  180   b  is an expandable reamer that is selectively extended and retracted from the tool  160   a ,  160   b  to engage and disengage the wellbore wall. The reamers  180   a ,  180   b  may also stabilize the drilling assembly  190  during downhole operations. In an aspect, the actuation or movement of the reamers  180   a ,  180   b  is powered by an actuation device  182   a ,  182   b , respectively. The actuation devices  182   a ,  182   b  are in turn controlled by controllers  184   a ,  184   b  positioned in or coupled to the actuation devices  182   a ,  182   b . The controllers  184   a ,  184   b  may operate independently or may be in communication with other controllers, such as the surface controller  140 . In one aspect, the surface controller  140  remotely controls the actuation of the reamers  180   a ,  180   b  via downhole controllers  184   a ,  184   b , respectively. The controllers  184   a ,  184   b  may be a computer-based unit that may include a processor, a storage device, such as a solid-state memory, tape or hard disc, and one or more computer programs in the storage device that are accessible to the processor for executing instructions contained in such programs. It should be noted that the depicted reamers  180   a ,  180   b  are one example of a tool or apparatus that may be actuated or powered by the actuation devices  182   a ,  182   b , which are described in detail below. In some embodiments, the drilling system  100  may utilize the actuation devices  182   a ,  182   b  to actuate one or more tools, such as reamers, steering pads and/or drilling bits with moveable blades, by selectively flowing of a fluid. Accordingly, the actuation devices  182   a ,  182   b  provide actuation to one or more downhole apparatus or tools  160   a ,  160   b , wherein the device is controlled remotely, at the surface, or locally by controllers  184   a ,  184   b.    
         [0018]      FIGS. 2A and 2B  are sectional side views of an embodiment a portion of a drill string, a tool and an actuation device, wherein the tool is depicted in two positions.  FIG. 2A  shows a tool  200  with a reamer  202  in a retracted (also referred to as “inactive” position or “closed” position).  FIG. 2B  shows the tool  200  with reamer  202  in an extended position (also referred to as “active” position or “open” position). The tool  200  includes an actuation device  204  configured to change positions or states of the reamer  202 . The depicted tool  200  shows a single reamer  202  and actuation device  204 , however, the concepts discussed herein may apply to embodiments with a plurality of tools  200 , reamers  202  and/or actuation devices  204 . For example, a single actuation device  204  can actuate a plurality of reamers  202  in a tool  200 , wherein the actuation device  204  controls fluid flow to the reamers  202 . As shown, the actuation device  204  is schematically depicted as a functional block, however, greater detail is shown in  FIGS. 3A and 3B . In an aspect, the reamer  202  includes or is coupled to an actuation assembly  206 , wherein the actuation device  204  and the actuation assembly  206  causes reamer  202  movement. Line  208  provides fluid communication between actuation device  204  and the actuation assembly  206 . The actuation assembly  206  includes a chamber  210 , sliding sleeve  212 , bleed nozzle  214  and check valve  216 . The sliding sleeve  212  (or annular piston) is coupled to the blade of reamer  202 , wherein the reamer  202  may extend and retract along actuation track  218 . In an aspect, the reamer  202  includes abrasive members, such as cutters configured to destroy a wellbore wall, thereby enlarging the wall diameter. The reamer  202  may extend to contact a wellbore wall as shown by arrow  219  and in  FIG. 2B . 
         [0019]    Still referring to  FIGS. 2A and 2B , in an aspect, drilling fluid  224  flows through a sleeve  220 , wherein the sleeve  220  includes a flow orifice  222 , flow bypass port  226 , and nozzle ports  228 . In one aspect, the actuation device  204  is electronically coupled to a controller located uphole via a line  230 . As described below, the actuation device  204  may include a controller configured for local control of the device. Further, the actuation device  204  may be coupled to other devices, sensors and/or controllers downhole, as shown by line  232 . For example, tool end  234  may be coupled to a BHA, wherein the line  232  communicates with devices and sensors located in the BHA. As depicted, the line  230  may be coupled to sensors that enable surface control of the actuation device  204  via signals generated uphole that communicate commands including the desired position of the reamer  202 . In one aspect, the line  232  is coupled to accelerometers that detect patterns in the drill string rotation rate, or RPM, wherein the pattern is decoded for commands to control one or more actuation device  204 . Further, an operator may use the line  230  to alter the position based on a condition, such as drilling a deviated wellbore at a selected angle. For example, a signal from the surface controller may extend the reamer  202 , as shown in  FIG. 2B , during drilling of a deviated wellbore at an angle of 15 degrees, wherein the extended reamer  202  provides stability while also increasing the wellbore diameter. It should be noted that  FIGS. 2A and 2B  illustrate non-limiting examples of a tool or device ( 200 ,  202 ) that may be controlled by fluid flow from the actuation device  204 , which is also described in detail with reference to  FIGS. 3A and 3B . 
         [0020]      FIGS. 3A and 3B  are schematic sectional side views of an embodiment of an actuation device  300  in two positions.  FIG. 3A  illustrates the actuation device  300  in an active position, providing fluid flow  301  to actuate a downhole tool, as described in  FIGS. 2A and 2B .  FIG. 3B  shows the actuation device  300  in a closed position, where there is no fluid flow to actuate the tool. In an aspect, the actuation device  300  includes a housing  302  and a piston  304  located in the housing  302 . The housing  302  includes a chamber  306  where an annular member  307 , extending from the piston  304 , is positioned. In an aspect, the housing  302  contains a hydraulic fluid  308  such as substantially non-compressible oil. The chamber  306  may be divided into two chambers,  309   a  and  309   b , by the annular member  307 . Further, the fluid  308  may be transferred between the chambers  309   a  and  309   b  by a flow control device  310  (or locking device), thereby allowing movement of the annular member  307  within chamber  306 . In an aspect, the housing  302  includes a port  312  that provides fluid communication with the line  208  ( FIGS. 2A and 2B ). When the piston  304  is in a selected active axial position, as shown in  FIG. 3A , a port  314  enables fluid communication from a fluid flow path  316  in the piston  304  (also referred to a flow path or an annulus) to port  312  and line  208 . In one aspect, a drilling fluid is pumped by surface pumps causing the fluid to flow downhole, shown by arrow  318 . Accordingly, as depicted in  FIG. 3A , the actuation device  300  is in an active position where drilling fluid flows from the flow path  316  through ports  314 ,  312  and into a supply line  208 , as shown by arrow  301 . In an aspect, the actuation device  300  includes a plurality of seals, such as ring seals  315   a ,  315   b ,  315   c ,  315   d  and  315   e , where the seals restrict and enable fluid flow through selected portions of the device  300 . As depicted, the flow control device  310  (also referred to as a “locking device”) uses a flow of fluid to “lock” the piston  304  in a selected axial position. It should be understood that any suitable locking device may be used to control axial movement by locking and unlocking the position of annular member  307  within chamber  306 . In other aspects, the locking device  310  may comprise any suitable mechanical, hydraulic or electric components, such as a solenoid or biased collet. 
         [0021]    With continued reference to  FIGS. 3A and 3B , a biasing member  320 , such as a spring, is coupled to the housing  302  and piston  304 . The biasing member  320  may be compressed and extended, thereby providing an axial force as the piston  304  moves along axis  321 . In an aspect, the flow control device  310  is used to control axial movement of the piston  304  within the housing  302 . As depicted, the flow control device  310  is a closed loop hydraulic system that includes a hydraulic line  322 , a valve  324 , a processor  326  and a memory device  328 , and software programs  329  stored in the memory device  328  and accessible to the processor  326 . The processor  326  may be a microprocessor configured to control the opening and closing of valve  324 , which is in fluid communication with chambers  309   a ,  309   b . In an embodiment, the processor  326  and memory  328  are connected by a line  330  to other devices, such as controller  140  at the surface ( FIG. 1 ) or sensors and controller in the drill string. In other embodiments, the flow control device  310  operates independently or locally, based on the control of the processor  326 , memory  328 , software  329  and additional inputs, such as sensed downhole parameters and patterns within sensed parameters. In another aspect, the flow control device  310  and actuation device  300  may be controlled by a surface controller, where signals are sent downhole by a communication line, such as line  330 . In another aspect, a sensor, such as an accelerometer, may sense a pattern in mud pulses, wherein the pattern communicates a command message, such as one describing a desired position for the actuation device  300 . As depicted, the piston  304  includes a nozzle  335  with one or more bypass ports  336 , where the nozzle  335  enables flow from the flow path  316  downhole. 
         [0022]    The operation of the actuation device  300  in reference to  FIGS. 3A and 3B , is discussed in detail below.  FIG. 3A  shows the actuation device  300  in an active position. The device  300  moves to an active position when drilling fluid flowing downhole  317  causes an axial force in the flow direction, pushing the piston  304  axially  333 , as it flows through the restricted volume of nozzle  335 . In an embodiment, the fluid flow axial force is greater than the resisting spring force of biasing member  320 , thereby compressing the biasing member  320  as the piston moves in direction  333 . In addition, the valve  324  is opened to allow hydraulic fluid to flow from chamber  309   b , substantially filling chamber  309   a . This enables movement of annular member  307  in chamber  306 , thereby enabling the piston  304  to move axially  333 . Accordingly, as the valve  324  is opened (or unlocked) the flow of drilling fluid, controlled uphole by mud pumps, provides an axial force to move piston  304  to the active position. As the chamber  309   a  is substantially full and chamber  309   b  is substantially empty, the valve  324  is closed or locked, thereby enabling the ports  312  and  314  to align and provide a flow path. In the active position, the drilling fluid flows through the nozzle  335  and bypass ports  336 , as flow from the ports  336  is not restricted by inner surface  338 . Accordingly, in the active position, the actuation device  300  provides fluid flow  301  to actuate one or more downhole tools, such as reamer  202  shown in  FIG. 2B . 
         [0023]    As shown in  FIG. 3B , the actuation device  300  is in a closed position, where the piston  304  has been moved axially  332  by the flow control device  310  and biasing member  320 , thereby stopping a flow of drilling fluid from the flow path  316  through ports  314  and  312 . To move to the closed position, the valve  324  is opened to enable hydraulic fluid to flow from chamber  309   a  to chamber  309   b , thereby unlocking the position annular member  307  within chamber  306  and enabling the piston  304  to move axially  332 . In addition, the flow of drilling fluid  317  is reduced or stopped to allow the force of biasing member  320  to cause piston  304  to move axially  332 . Once the piston  304  is in the desired closed position, where the ports  312  and  314  are not in fluid communication with each other, the valve  324  is closed to lock the piston  304  in place. In the closed position, the chamber  309   a  is substantially empty and the chamber  309   b  is substantially full. In addition, in the closed position of actuation device  300 , drilling fluid does not flow through the bypass ports  336 , which are restricted by inner surface  338 . Thus, the actuation device  300  in a closed position shuts off fluid flow and corresponding actuation to one or more tools operationally coupled to the device, thereby keeping the tool, such as a reamer  202  ( FIG. 2A ) in a neutral position. 
         [0024]    Referring back to  FIG. 1 , in an aspect, one or more downhole devices or tools, such as the reamers  180   a ,  180   b , are controlled by and communicate with the surface via pattern recognition signals transmitted through the drill string. The signal patterns may be any suitable robust signal that allows communication between the surface drilling rig and the downhole tool, such as changes in drill string rotation rate (revolutions per minute or “RPM”) or changes in mud pulse frequency. In an aspect, the sequence, rotation rate speed (RPM) and duration of the rotation is considered a pattern or pattern command that is detected downhole to control one or more downhole tools. For example, the drill string may be rotated at 40 RPM for 10 seconds, followed by a rotation of 20 RPM for 30 seconds, where one or more sensors, such as accelerometers or other sensors, sense the drill string rotation speed and route such detected speeds and corresponding signals to a processor  326  ( FIGS. 3A and 3B ). The processor  326  decodes the pattern to determine the selected tool position sent from the surface and then the actuation device  300  ( FIGS. 3A and 3B ) causes the tool to move to the desired position. In another aspect, a sequence of mud pulses of a varying parameter, such as duration, amplitude and/or frequency may provide a command pattern received by pressure sensors to control one or more downhole devices. In aspects, a plurality of downhole tools may be controlled by pattern commands, wherein a first pattern sequence triggers a first tool to position A and a second pattern sequence triggers a second tool to second position B. In the example, the first and second patterns may be RPM and/or pulse patterns that communicate specific commands to two separate tools downhole. Thus, RPM pattern sequences and/or pulse pattern sequences in combination with a tool and actuation device, such as the actuation device described above, and sensors enable communication with and improved control of one or more downhole devices. 
         [0025]    While the foregoing disclosure is directed to certain embodiments, various changes and modifications to such embodiments will be apparent to those skilled in the art. It is intended that all changes and modifications that are within the scope and spirit of the appended claims be embraced by the disclosure herein.