Patent Publication Number: US-8528636-B2

Title: Instantaneous measurement of drillstring orientation

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application takes priority from U.S. Provisional Application Ser. No. 60/844,185 filed on Sep. 13, 2006. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates generally to drilling assemblies that utilize an orientation sensing system. 
     2. Description of the Related Art 
     Valuable hydrocarbon deposits, such as those containing oil and gas, are often found in subterranean formations located thousands of feet below the surface of the Earth. To recover these hydrocarbon deposits, boreholes or wellbores are drilled by rotating a drill bit attached to a drilling assembly (also referred to herein as a “bottom hole assembly” or “BHA”). Such a drilling assembly is attached to the downhole end of a tubing or drill string made up of jointed rigid pipe or a flexible tubing coiled on a reel (“coiled tubing”). For directional drilling, the drilling assembly can use a steering unit to direct the drill bit along a desired wellbore trajectory. 
     Wellbore drilling systems can also use measurement-while-drilling (MWD) and logging-while-drilling (LWD) devices to determine wellbore parameters and operating conditions during drilling of a well. These parameters and conditions may include formation density, gamma radiation, resistivity, acoustic properties, porosity, and so forth. Many of these tools are directionally sensitive in that, to be meaningful, the measurements made by these tools should be correlated or indexed with a frame of reference for the formation. In one convention, the angular difference between a reference point on a tool and a frame of reference such as borehole highside or magnetic north is referred to as a toolface angle. As is conventionally understood, the term “borehole highside” is an uppermost side of a non-vertical borehole. It is commonly required to present the output from imaging sensors oriented with reference to the borehole highside. Conventionally, the methodology for determining a toolface of an imaging sensor involves the use of magnetic sensing devices because the shocks, vibrations, and centrifugal forces associated with a rotating system can unduly interfere with the operation of devices such as accelerometers that could provide a direct measurement of highside. The problems encountered with such conventional devices and methods include inaccurate or outdated conversions between magnetic toolface and highside, inaccuracy due to magnetic junk or hotspots, eddy currents induced in a rotating conductive collar, and errors caused by electric currents flowing in proximity to the sensor. In addition, while it is desirable to continuously measure the azimuth of the borehole while drilling, the value of such measurements has been limited due to the difficulty of accurately measuring transverse acceleration components of a rotating system. 
     The present invention is directed to addressing one or more of the above stated drawbacks for determining the orientation of logging tools and other components of a drilling system. 
     SUMMARY OF THE INVENTION 
     In one aspect, an orientation measurement system is deployed in a wellbore drilling system having at least one rotating section and one or more non-rotating sections. One or more reservoir imaging and characterization tools, directional tools, and/or other known bottomhole assembly (BHA) tools are positioned in the rotating section. The non-rotating section can include a non-rotating sleeve associated with a stabilizer or a steering unit. The orientation measurement system includes a processor, a rotary position sensor and an orientation sensor. The processor receives signals from the rotary position sensor, which measures an angular position of the rotating section relative to the non-rotating section. The processor also receives signals from the orientation sensor, which determines the orientation of the non-rotating section relative to a reference frame such as borehole highside. The processor uses the first and second signals to determine a tool face of the rotating member relative to the highside and periodically and/or continuously transmits the determined tool face along the BHA via a suitable communication link. The determined tool face is used by the BHA tools to synchronize measurements with highside and/or to determine borehole azimuth. 
     It should be understood that examples of the more important features of the invention have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features of the invention that will be described hereinafter and which will form the subject of the claims appended hereto. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For detailed understanding of the present invention, references should be made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein: 
         FIG. 1  shows a schematic diagram of a drilling system with a bottom hole assembly according to one embodiment of the present invention; 
         FIG. 2  shows a sectional schematic view of one orientation measurement system made in accordance with one embodiment of the present invention; 
         FIG. 3  illustrates the relationships of the measured angular offsets in accordance with one embodiment of the present invention; 
         FIG. 4  sectional schematic view of one rotary position sensor made in accordance with one embodiment of the present invention; and 
         FIG. 5  sectional schematic view of another rotary position sensor made in accordance with one embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     The present invention relates to devices and methods providing orientation information for drilling system adapted to drill a wellbore in a subterranean formation. The present invention is susceptible to embodiments of different forms. There are shown in the drawings, and herein will be described in detail, specific embodiments of the present invention with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. 
     Referring initially to  FIG. 1  there is shown a schematic diagram of a drilling system  10  having a bottom hole assembly (BHA) or drilling assembly  100  conveyed via a drill string  20  into a borehole  12  formed in a formation  14 . The BHA  100  includes a drilling motor  102  for rotating a drill bit  104 , a steering assembly  106  for steering the drill bit  104  in a selected direction, one or more BHA processors  108 , one or more stabilizers  110 , and other equipment known to those skilled in the art. The drill string  20  may include a tubing  101  formed of jointed drill pipe or coiled tubing. The drill string  20  may include one or more signal conductors that are configured to convey data signals and/or power along the drill string  20 . The drill bit  104  may be rotated in any one of three modes: rotation by only the tubing  101 , rotation by only the drilling motor  102 , and rotation by a combined use of the tubing  101 , and drilling motor  102 . The BHA  100  also includes a logging tool  300 , which may include a suite of tool modules, that obtain information relating to the geological, geophysical and/or petrophysical characteristics of the formation  14  being drilled. 
     Referring now to  FIG. 2 , there are shown a section of a logging tool  300  and a steering unit  200 . The logging tool  300 , for illustrative purposes is shown as including three separate tool modules  302 ,  304 ,  306 . These tool modules can measure parameters of interest such as gamma rays, resistivity, density, acoustic properties, and porosity. Other exemplary tools include radiation tools, tools for induction logs, ultra sonic caliper, and nuclear magnetic resonance tools (NMR). As is known, one or more of these tools can be directionally sensitive. That is, the direction the tool is pointing when taking a measurement must be known to make full use of the measurements. In one convention, the angular position of the tool relative to a reference frame, such as borehole highside, is defined as a “tool face” of the tool module  302 . For example, using the sensor&#39;s sensitive axis as the reference point, the measurements of the tool module  302  can be correlated with a selected formation reference point such as borehole “highside,” e.g., a measurement&#39;s tool face can be reported as 90 degrees from highside. In embodiments where the tool modules  302 ,  304 ,  306  are positioned on a rotating section of the drill string  20  ( FIG. 1 ), the tool face of the tool module  302  rotates relative to the borehole highside. Thus, it is desirable to periodically and/or continuously determine the tool face of the tool module  302  relative to highside or other selected reference frame while the tool module  302  is making measurements. 
     Accordingly, embodiments of the BHA  100  include an orientation measurement system  400  that determines the orientation of a selected reference point on the rotating portion  204  of the drill string  20  ( FIG. 1 ) relative to a highside or other selected reference frame. In one configuration, the orientation is expressed as an angular value between the selected reference point and highside. This angular value will be referred to as the “tool face.” This determined tool face can be used by tool modules  302 ,  304 ,  306  to correlate their measurements with “borehole highside.” 
     An exemplary orientation measurement system  400  is used in conjunction with the device  200  having a non-rotating section  202  and a rotating section  204 . The logging tool  300  is coupled to and rotates with the rotating section  204 . The orientation measurement system  400  includes a processor  402  that receives a first signal from a rotary position sensor  404  that determines the angular position of the rotating section  204  relative to the non-rotating section  202  and receives a second signal from an orientation sensor  406  that determines the orientation of the non-rotating section  202  relative to a reference frame such as highside. The processor  402  is programmed with instructions to use the first and second signals to determine a tool face of the rotating member  204  relative to the borehole highside. The processor  402  periodically and/or continuously transmits the determined tool face along the BHA  100  via a communication link  408 . The determined tool face can be used by the tool  300  to immediately correlate measurements or can be saved in a memory for correlation of the data at a later time. The determined tool face data can also be transmitted to the surface. 
     In one arrangement, the device  200  can be a BHA steering assembly wherein the non-rotating member  202  is a non-rotating sleeve and the rotating member  204  is a mandrel. The steering assembly also includes a plurality of force application members  206  that selectively engage the borehole wall  106  of the wellbore  12  to thereby lock or anchor the non-rotating sleeve  202  to the wall  106 . The non-rotating sleeve  202  might slightly rotate due to the frictional forces between the non-rotating sleeve  202  and a rotating mandrel  204  on which the non-rotating sleeve  202  is mounted. It should be understood, however, that the present invention is not limited to use of a steering assembly. Other suitable devices can include a drill string stabilizer  110  ( FIG. 1 ) having a non-rotating sleeve or other similar device having a rotating and non-rotating component. 
     The orientation sensor  406  can be positioned on the non-rotating sleeve  202  to determine the orientation of the non-rotating sleeve  202  relative to a selected reference frame and transmit a responsive signal. Typically, the reference frame is borehole highside, but it can be magnetic north or some other selected frame of reference. For example, the orientation sensor  406  can include a multi-axis accelerometer that transmits a signal indicative of the orientation of the non-rotating sleeve relative to highside; i.e., the tool face of the non-rotating sleeve  202 . The data from the orientation sensor  406  can be transmitted via a suitable coupling  409  (e.g., electrical slip rings, RF signals or inductive coupling) from the non-rotating sleeve  202  to the rotating mandrel  204 . The processor  402  is operatively coupled to and receives data from the orientation sensor  406  via the coupling  409 . 
     An exemplary rotary position sensor  404  transmits a signal indicative of the orientation of the rotating member  204 , such as a mandrel, relative to the non-rotating section  202 , such as the non-rotating sleeve. In one embodiment, the rotary position sensor  404  is configured to transmit a signal when a specified orientation exists between the non-rotating member  202  and the rotating member  204 . For instance, the rotary position sensor  404  can transmit a signal when the non-rotating member  202  and the rotating member  204  are aligned, which then means that the tool face angles for both devices are the same. This type of arrangement may be useful for directional surveys wherein drilling motions limit the accuracy of the toolface sensors in the directional module. In another embodiment, the rotary position sensor  404  continually transmits a signal indicative of the orientation of the rotating member  204  relative to the non-rotating sleeve  202 . Under this continuous or instantaneous signal transmission scenario, the tool face angle is continuously determined and transmitted across the BHA  100 , including the logging tool  300 . Therefore, the logging tool  300 , with its constituent modules, can continuously synchronize their measurements with the determined tool face angle. 
     Referring now to  FIGS. 2 and 3 , in one mode of operation, the orientation sensor  406  determines the orientation of a reference point  410  on the non-rotating sleeve  202  relative to the highside H of the wellbore and transmits a signal indicative of this orientation to the processor  402 . At the same time, the rotary position sensor  404  determines the tool face of a reference point  412  on the rotating mandrel  204  relative to a reference point  410  on the non-rotating sleeve  202  and transmits an indicative signal to the processor  402 . The processor  402  sums the two angles to determine a tool face angle of the rotating mandrel relative to the highside H. For illustrative purposes, a reference point  410  on the non-rotating sleeve  202  is shown as having a tool face of α degrees from the highside H of the wellbore and the reference point  412  on the mandrel is shown as having a tool face of β degrees from the reference point  410 . Thus, the tool face angle of the rotating mandrel relative to the highside H is α+β. 
     The processor  402  transmits the determined tool face (a+13) along the BHA  100  via the communication link  408 . The communication link can utilize wires such as electrical conductors or fiber optics, wired pipe, magnetic signals, acoustic signals, pressure pulses, RF transmission or any other suitable signal transmission media. When the tool modules  302 ,  304 ,  306  receive the tool face angle, an additional calculation may have to be performed to determine the tool face angle of each of these tool modules  302 ,  304  and  306  relative to highside H. As is known, each tool module  302 ,  304  and  306  can have a separate reference point  416 ,  418 ,  420 , respectively, that is rotationally offset relative to the reference point  412  of the mandrel by angles θ′, θ″, θ′″, respectively. These offsets  416 ,  418 ,  420  are determined at the time the BHA  100  is made up or can be determined downhole when the tool modules  302 ,  304 ,  306  are not rotating. Determination of the tool face angles for reference points  416 ,  418 ,  420 , relative to highside H, therefore, will require adding the angles θ′, θ″, and θ′″, to the summation (α+β), respectively. This correction can be performed using the processor  402 , a suitable processor in the tool  300  or at the surface. Thereafter, the data acquired by the modules  302 ,  304  and  306  can be readily oriented with the highside H of the wellbore. 
     Additionally, at one of the modules  302 ,  304  or  306 , the tool face angle data can be used to calculate azimuth while rotating. Azimuth is the angle between the horizontal component of a borehole direction at a particular point and the direction of north. The angle can be expressed in the 0-360 degree system. The angle may refer to either magnetic, true (geographic), or grid north. One known method for determining magnetic azimuth A in the static case uses the following equation:
 
 A=a  tan [{ G ·( B   y   ·G   x   −B   x   ·G   y )}/{ B   z ·( G   x   2   +G   y   2 )− G   z ·( B   x   ·G   x   +B   y   ·G   y )}]  (1)
 
Where G (acceleration due to gravity)=√(G x   2 +G y   2 +G z   2 ). In accordance with one embodiment of the present invention, azimuth is calculated using the following equation:
 
 A=a  tan [{ B   xy ·sin( M−T )}/{ B   z ·sin/+ B   xy ·cos/·cos( M−T )}]  (2)
 
where B xy =√(B x   2 +B y   2 ), M (magnetic toolface)=tan −1  (B x /B y ), and T (highside toolface)=tan −1 [(−Gx)/(−Gy)].
 
The above equation, which should be understood as merely illustrative, determines the toolface offset (M−T) using: (i) the tool face data indicative of gravity toolface at non-rotating sleeve, (ii) magnetic tool face at the module as determined by a suitable sensor, and (iii) a sleeve-to-mandrel relative rotary position measured directly by one of several methods which are generally known. One or more processors at the modules  302 ,  304 ,  306  can be programmed to calculate azimuth. The processors can include appropriate instructions to synchronize magnetic data at the modules  302 ,  304 ,  306  with the tool face data. While Gz may be obtained from either node, it is preferred from the directional node since this sensor is better aligned with the Bz sensor.
 
     The processor at the tool  300  can also compensate for eddy current effects that tend to bias measured magnetic measurements while rotating. Exemplary compensation techniques are described in U.S. Pat. No. 5,012,412, which is hereby incorporated by reference for all purposes. In embodiments, where the sleeve-to-mandrel angle is measured magnetically, the need for compensation may be reduced because the M and the sleeve-to-mandrel angle could be biased similarly. In calculating instantaneous azimuth, it will be particularly important to account for delays in transmission of toolface between nodes, and also to compensate for eddy currents which affect the transverse magnetometer measurements. 
     It is believed that torsional acceleration can affect the above computations in extreme operating conditions, such as during reverse rotation of the drill bit. Sensors suitable to accurately measure tool face during such conditions should measure the non-rotating sleeve-to-rotating member angle directly, not just by inferential methods, e.g., counting events from a reference mark. 
     Any number of arrangements can be utilized for the rotary position sensor  400 . The arrangements can be configured to meet a specified application. A few illustrative embodiments are discussed below. 
     Referring now to  FIG. 4 , in one embodiment, a rotary position sensor  404  includes a first member or element  412  positioned on the non-rotating sleeve  202 , and a second member or element  414  positioned on the rotating member  204 . This first member  412  is positioned at a fixed relationship with respect to a selected reference point on the non-rotating member  202 . The second member  414  either actively or passively detects the first member  412 . These position signals can be generated, for example, when the first member  412  is proximate to the second member  414  or in a specified relationship with each other. In another arrangement, a position signal can be emitted when the first member  412  is not proximate to the second member  414 . For example, the first member  412  can actively emit a signal such as an electrical signal, a magnetic signal, or an acoustic signal. In a passive arrangement, the first member  412  can be a discontinuity that is actively detected by the second member  414 . In other arrangements, the first member  412  can be positioned on the rotating member  204  and the second member can be positioned on the non-rotating member  202 . It will be apparent to one of ordinary skill in the art that other arrangements may be used in lieu of magnetic signals. Such other arrangements for detecting orientation include inductive transducers (linear variable differential transformers), coil or hall sensors, and capacity sensors. Still other arrangements can use radio waves, electrical signals, acoustic signals, optical signals, and interfering physical contact between the first and second members. 
     Referring now to  FIG. 5 , in another embodiment, the non-rotating sleeve  202  can include one or more position markers such as a discontinuity, e.g., a projection or depression  460 . One or more Hall effect type sensors  462  or other suitable sensors on the rotating mandrel  204  detects the position marker(s) and sends a responsive signal to the processor. In one arrangement, the discontinuity can be a missing tooth or an extra tooth at a pre-determined position. The sensor  462  can be configured to detect the gap or the extra projection. In another arrangement, the sensor  462  is configured to precisely determine the angular relationship of the non-rotating sleeve  202  and the rotating mandrel  204  at any time. In embodiments utilizing a plurality of sensors, the sensors  464   a - c  can be circumferentially arrayed around the mandrel  204  to determine angular relationship at any time and to positively identify the direction of rotation. With multiple sensors, the progression of the detection of the sensors can be monitored. Any non-sequential detection by the sensors, can indicate a backward rotation of the drill string. While the sensors are shown on the rotating mandrel, in certain arrangements the sensors can be positioned on the non-rotating sleeve and the discontinuity or position marker formed on the rotating mandrel. 
     Referring now to  FIG. 1 , embodiments of the present invention can be utilized with the drilling system  10  adapted for either land or offshore drilling. For land based drilling, the drilling system  10  includes a conventional derrick  11 . The drill string  20 , which includes a tubing (drill pipe or coiled-tubing)  101 , extends downward from the surface into the borehole  12 . A tubing injector  14   a  is used to inject the BHA  100  into the wellbore  12  when a coiled-tubing is used. The drill bit  104  attached to the drill string  20  disintegrates the geological formations when it is rotated to drill the borehole  12 . During drilling, a suitable drilling fluid  31  from a mud pit (source)  32  is circulated under pressure through the drill string  20  by a mud pump  34 . The drilling fluid  31  discharges at the borehole bottom  51  through openings in the drill bit  104  and returns to the mud pit  32  via a return line  35 . 
     The drilling system also includes a bi-directional communication link  39  and surface sensors, collectively referred to with S 2 . The communication link  39  enables two-way communication between the surface and the drilling assembly  100 . The communication link  39  may be mud pulse telemetry, acoustic telemetry, electromagnetic telemetry or other suitable communication system. The surface sensors S 2  include sensors that provide information relating to surface system parameters such as fluid flow rate, torque and the rotational speed of the drill string  20 , tubing injection speed, and hook load of the drill string  20 . The surface sensors S 2  are suitably positioned on surface equipment to detect such information. These sensors generate signals representative of its corresponding parameter, which signals are transmitted to a processor by hard wire, magnetic or acoustic coupling. The sensors generally described above are known in the art and therefore are not described in further detail. 
     The drilling system  10  includes surface and/or downhole processors to control BHA  100  operation. In one embodiment, the drilling system  10  includes a control unit  40  and one or more BHA processors  44  that cooperate to analyze sensor data and execute programmed instructions to achieve more effective drilling of the wellbore. The control unit  40  and BHA processor  44  receives signals from one or more sensors and process such signals according to programmed instructions provided to each of the respective processors. The surface control unit  40  displays desired drilling parameters and other information on a display/monitor  41  that is utilized by an operator to control the drilling operations. Each processor  40 , 44  contains a computer, memory for storing data, recorder for recording data and other known peripherals. 
     During operation, the drill bit forms the wellbore by disintegrating the formation and thereby advancing the drill string there through. At the same time, the logging tool  300  is measuring various parameter of interest relating to the formation being intersected by the wellbore. When desired, the orientation measurement system  400  ( FIG. 2 ) determines the tool face of the rotating mandrel relative to borehole highside and transmits or broadcasts the determined tool face to the several components making up the BHA  100 . The logging tool  300  receives the tool face and uses this information to correlate measurements to highside. A continuously broadcast determined tool face angle is used by tools such as reservoir imaging and characterization tools. A continuously or periodically broadcast determined tool face angle can be used by directional tools to calculate azimuth as needed. Of course, other components in the BHA  100 , e.g., the steering unit, can also utilize such orientation data. 
     In some embodiments, the output of the orientation measurement system  400  ( FIG. 2 ) is correlated with the measurements of the logging tool  300  downhole. That is, for example, azimuthal information can be correlated with the logging tool measurements downhole while drilling is on-going. In such an arrangement, the logging tool measurements are immediately associated with and orientation measurement. In other embodiments, the output of the orientation measurement system  400  ( FIG. 1 ) may be associated with a separate reference such as time. Likewise, the logging tool measurements may be stored and associated the same reference. Thus, at a later point, while downhole or at the surface, the logging tool measurements and the orientation measurements may be correlated using the common reference. 
     The foregoing description is directed to particular embodiments of the present invention for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above are possible without departing from the scope of the invention. It is intended that the following claims be interpreted to embrace all such modifications and changes.