Abstract:
An apparatus, device or system according to one or more aspects includes a first-type diamond semiconductor moveably positioned relative to a second-type diamond semi-conductor, the first-type diamond semiconductor operationally connected to a tool element, the first-type diamond semiconductor moving relative to the second type diamond semiconductor in response to movement of the tool element, and an electrical signal created in response to the first-type and the second-type diamond semi-conductors moving in and out of contact with one another, where the electrical signal or electrical signals are indicative of a monitored condition.

Description:
[0001]    CROSS-REFERENCE TO RELATED APPLICATION(S) 
         [0002]    This application claims the benefit of and priority to U.S. Provisional Application Ser. No. 62/144,303, filed Apr. 7, 2015, which is incorporated herein by reference in its entirety. 
     
    
     BACKGROUND 
       [0003]    This section provides background information to facilitate a better understanding of the various aspects of the disclosure. It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art. 
         [0004]    Wells are generally drilled into the ground to recover natural deposits of hydrocarbons and other desirable materials trapped in geological formations in the Earth&#39;s crust. A well is typically drilled using a drill bit attached to the lower end of a drill string. The well is drilled so that it penetrates the subsurface formations containing the trapped materials and the materials can be recovered. 
         [0005]    A variety of valves are used to control flow of actuating fluids in many well applications and other flow control applications. For example, valves are employed in wellbore drilling to control the actuation of tools located in the wellbore being drilled. During wellbore drilling operations, valves positioned in the downhole drilling assembly can be actuated to control the direction of drilling. The valves may be positioned, for example to control the flow of drilling mud to actuating pads which are extended and contracted in a controlled manner to steer the drill bit in the desired direction. In some applications a valve, or valve-type member is actuated to repeatedly interrupt the flow of the drilling fluid to cause varying pressure waves to be generated in the drilling fluid at a carrier frequency to provide signal communication between downhole systems and with the surface. It is desired to know the rotational speed of this valve members and whether or not the device has become blocked due to solids in the drilling fluid. Other factors such as wear, breakage, position of the valve member and the like also contribute to the efficiency of the tool. 
       SUMMARY 
       [0006]    An apparatus, device or system in accordance to one or more aspects includes a first-type diamond semiconductor moveably positioned relative to a second-type diamond semi-conductor, the first-type diamond semiconductor is operationally connected to a tool element and the first-type diamond semiconductor moves relative to the second type diamond semiconductor in response to movement of the tool element, and an electrical signal indicative of a monitored condition is created in response to the first-type and the second-type diamond semi-conductors moving in and out of contact with one another. In accordance to an aspect of the disclosure a wellbore system includes a downhole tool having a moveable tool element disposed with a tubular string in a wellbore and a switching device operationally connected with the downhole tool and including a first-type diamond semiconductor moveably positioned relative to a second-type diamond semi-conductor, the first-type diamond semiconductor operationally connected to the tool element such that the first-type diamond semiconductor moves relative to the second type diamond semiconductor in response to movement of the tool element, and an electrical signal is created in response to the first-type and the second-type diamond semi-conductors moving in and out of contact with one another. 
         [0007]    A method according to an aspect of the disclosure includes monitoring a condition of a downhole tool disposed in a wellbore, the downhole tool having a first-type diamond semiconductor moveably positioned relative to a second-type diamond semi-conductor and the first-type diamond semiconductor operational connected to a tool element of the downhole tool such that the first-type diamond semiconductor moves relative to the second type diamond semiconductor in response to movement of the tool element; and creating an electrical signal that is indicative to the monitored condition in response to the first-type and the second-type diamond semi-conductors moving in and out of contact with one another. 
         [0008]    This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of claimed subject matter. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0009]    Embodiments of diamond switching mechanisms, systems and methods are described with reference to the following figures. The same numbers are used throughout the figures to reference like features and components. It is emphasized that, in accordance with standard practice in the industry, various features are not necessarily drawn to scale. In fact, the dimensions of various features may be arbitrarily increased or reduced for clarity of discussion. 
           [0010]      FIGS. 1 and 2  illustrate wellbore systems in which a diamond switching device in accordance to aspects of the disclosure can be implemented. 
           [0011]      FIG. 3  is a schematic illustration of a diamond switching device in accordance with one or more embodiments. 
           [0012]      FIGS. 4 and 5  illustrate a diamond switching device utilized with a rotary valve in a downhole drilling tool in accordance to one or more aspects of the disclosure. 
       
    
    
     DETAILED DESCRIPTION 
       [0013]    It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. 
         [0014]      FIGS. 1 and 2  illustrate examples of wellbore systems  100  in which diamond switch, or switching, devices generally denoted by the numeral  50  may be utilized. As will be understood by those with benefit of this disclosure the diamond switching device  50  can also be utilized in non-drilling wellbore systems and non-wellbore systems. 
         [0015]    The diamond switching mechanism may be utilized in various tools for example, and without limitation, to monitor the position, orientation and the speed of a device such as rotary or linear valve, to determine potential blockage of a valve, and be utilized as a switch to power and/or control another process or device. By way of example, diamond switching device  50  is illustrated being utilized with a mud pulse telemetry device  38  (e.g., fluidic modulator) in  FIGS. 1 and 2  and with a valve of a rotary steering system  48  in  FIG. 2 . As will be understood by those skilled in the art with benefit of this disclosure, the diamond switching device can be utilized to control and/or monitor the speed or position of devices other than the depicted fluidic modulator and rotary steering system valve. 
         [0016]    Wellbore system  100 , which may be on-shore or off-shore, is depicted having a drilling rig  10  which includes a drive mechanism  12  to provide a driving torque to a drill string  14 . The lower end of the drill string  14  extends into a wellbore  30  and carries a drill bit  16  to drill an underground formation  18 . During drilling operations, drilling fluid  20  is drawn from a mud pit  22  at a surface  29  via one or more pumps  24 , such as, for example, one or more reciprocating pumps. The drilling fluid  20  is circulated through a mud line  26  down through the drill string  14  as indicated by the directional arrow  8 , through the drill bit  16 , and back to the surface  29  via an annulus  28  between the drill string  14  and the wall of the wellbore  30  as indicated by the direction arrow  9 . Upon reaching the surface  29 , the drilling fluid  20  is discharged through a line  32  into the mud pit  22  so that drill cuttings, such as, for example, rock and/or other well debris carried uphole in the drilling mud can settle to the bottom of the mud pit  22  before the drilling fluid  20  is recirculated into the drill string  14 . 
         [0017]    Drill string  14  includes a bottom hole assembly (“BHA”)  33 , which includes at least one downhole tool  34 . Downhole tool  34  may comprise survey or measurement tools, such as, logging-while-drilling (“LWD”) tools, measuring-while-drilling (“MWD”) tools, near-bit tools, on-bit tools, and/or wireline configurable tools. LWD tools may include capabilities for measuring, processing, and storing information, as well as for communicating with surface equipment. Additionally, LWD tools may include one or more of the following types of logging devices that measure characteristics associated with the formation  18  and/or the wellbore: a resistivity measuring device; a directional resistivity measuring device; a sonic measuring device; a nuclear measuring device; a nuclear magnetic resonance measuring device; a pressure measuring device; a seismic measuring device; an imaging device; a formation sampling device; a natural gamma ray device; a density and photoelectric index device; a neutron porosity device; and a borehole caliper device. A LWD tool is identified specifically with the reference number  120  in  FIG. 2 . 
         [0018]    MWD tools may include for example one or more devices for measuring characteristics adjacent drill bit  16 . MWD tools may include one or more of the following types of measuring devices: a weight-on-bit measuring device; a torque measuring device; a vibration measuring device; a shock measuring device; a stick slip measuring device; a direction measuring device; an inclination measuring device; a natural gamma ray device; a directional survey device; a tool face device; a borehole pressure device; and a temperature device. MWD tools may detect, collect and/or log data and/or information about the conditions at the drill bit  16 , around the underground formation  18 , at a front of the drill string  14  and/or at a distance around the drill strings  14 . A MWD tool is identified with the reference number  130  in  FIG. 2 . 
         [0019]    Downhole tool  34  may comprise a downhole power source, for example, a battery, downhole motor, turbine, a downhole mud motor or any other power generating source. The power source may produce and generate electrical power or electrical energy to be distributed throughout the BHA  33  and/or to power the at least one downhole tool  34 . 
         [0020]    The downhole tool  34  depicted in  FIG. 1  includes a sensor  36 , e.g., sensor assembly, data source, and a fluidic modulator  38  for mud pulse telemetry in accordance to one or more aspects of this disclosure. Fluidic modulator  38  is operated to disrupt the flow of the drilling fluid  20  through the drill string  14  to cause pressure pulses or changes fluid flow. The pressure pulses are modulated by operation of the fluidic modulator and thereby encoded for telemetry purposes. System  100  depicted in  FIG. 2  includes more than one fluidic modulator  38  each of which may be utilized to modulate pressure pulses in the drilling fluid  20  to transmit data (e.g., control signals) downhole and/or to transmit downhole measurements to the surface. In accordance to aspects of the disclosure the flow path through the fluidic modulator  38  is co-axial with the flow path through the drill string. The fluidic modulator  38  is operated so as to create a pressure change in the drilling fluid in the wellbore and in the mud line  26  that is encoded with data for example from the downhole data source  36 . The modulated changes in the pressure of the drilling fluid  20  may be detected at the surface by a pressure transducer  40  and/or a pump piston sensor  42 , both of which may be coupled to a processor  44  located at the surface ( FIG. 2 ). The fluidic modulators  38  may be associated downhole with processor  44  as well, see e.g.  FIG. 2 . The processors  44  may interpret the modulated changes in the pressure of drilling fluid  20  to reconstruct the measurements, data and/or information collected at the sensors  36  and sent by the fluidic modulators. The processor  44  may also encode data such that the fluidic modulator is actuated to modulate the pressure pulses to transit the encoded data. The processor  44  may be utilized as a controller to operate the position of the valve or tool element. The modulation and demodulation of a pressure wave are described in detail in commonly assigned U.S. Pat. Nos. 5,375,098 and 8,302,685, which are incorporated by reference herein in their entirety. In accordance to aspects of the disclosure the fluidic modulators  38  may incorporate or be operationally connected with a diamond switching device  50  which may be utilized to monitor the position, condition and/or speed of the operational member (tool element) of the fluidic modulator  38  and/or to control or operate the fluidic modulator. 
         [0021]      FIG. 2  illustrates a BHA  33  including a drilling motor  46  (e.g., mud motor), a rotary steering system (“RSS”)  48  and drill bit  16 . In accordance with some embodiments, drilling motor  46  converts fluid power in the downward mud flow into rotary motion. The rotary motion is transmitted to the portions of the BHA below mud motor  46 . The drilling motor  46  may comprise a positive displacement motor (“PDM”) or turbodrill.  FIG. 2  illustrates a rotary steering system (“RSS”)  48  connected below the drilling motor  46 . As illustrated for example in  FIG. 6 , RSS  48  includes pads that are selectively actuated by hydraulic fluid and a rotary valve to steer the drill bit. In accordance to one or more aspects, a diamond switching device  50  is operationally connected with the rotary steering system. 
         [0022]    Many rotary steerable drilling tools operate using a reciprocating motion valve to divert mud flow, be it rotary or linear, see, e.g., U.S. Pat. No. 8,708,064, the teachings of which are incorporated herein. When a rotary steerable tool is being used it is vital to know the RPM of the valve and whether or not it has become blocked due to solids in the mud. Many other factors such as wear, breakage, position of the valve etc. contribute to the efficiency of the tool. 
         [0023]    A means of monitoring the RPM, position, orientation of a valve or whether it has been blocked is problematic due to the harsh environment the valve operates in. Many sensors that could be used to measure these criteria cannot operate in mud, high pressure, temperature or abrasives. A function of synthetic diamond is that it can be doped with either boron or phosphorus to make it behave as a p-type or n-type semiconductor respectively. By using a pair of these doped diamonds a diode type switching mechanism can be made. If three of these switching mechanisms  50  were to be used a transistor could effectively be made. 
         [0024]      FIG. 3  schematically illustrates diamond switching mechanism, generally denoted with the numeral  50 , in accordance to one or more aspects of the disclosure. A rotor tab  52  may be made from diamond doped, for example, with boron. The illustrated rotor tab  52  may be connected to a moveable tool member, for example a valve member, a drive shaft or the like, such that rotor tab  52  moves with the moveable tool member. In the illustrated example, rotor tab  52  is an n-type diamond semiconductor. Electrical contact could be made for example through the bottom of the rotor tab via a slip ring or bearing arrangement. Rotor tab  52  is positioned so as to rotate freely relative to a stator  54 , e.g., cylinder, made of a non-conductive material, such as tungsten carbide (WC) or non-doped diamond (e.g., polycrystalline diamond). A disc or stator tab  56  of, for example, phosphorus doped diamond may be set into the wall of the stator  54  in line vertically with the rotor tab  52 . In the illustrated example, the stator tab  56  is a p-type semiconductor. One or more stator tabs  56  may be positioned circumferentially and/or vertically along the stator. In some embodiments, the clearance between the rotor tab  52  and the stator tab  56  is such that they contact as the rotor rotates. 
         [0025]    In use an electrical current is applied to the rotor tab  52 . When the rotor tabs  52  and stator  56  are not in contact the circuit is broken. When the rotor tab  52  and the stator tab  56  are in contact the circuit is closed and a signal of some description is created. One or more tabs could be placed in the cylinder and the rotor to allow for additional signal and functionality, such as creating a transistor. This methodology could be applied both to a fully rotating rotor, an oscillating rotor or linear valve or any number of other designs. Through processing these signals it is possible to determine the speed of the valve (RPMs), position of the valve (which could be increased by adding more than 1 tab) and potential blockage of the valve. It could also be used as a switch to power/control another process or device or any number of other actions. 
         [0026]    In accordance to an aspect, the diamond switching device, or mechanism,  50  is utilized to control or monitor the speed or position of a valve member or other moveable element of a downhole tool such as a fluidic modulator  38  in a similar manner as discussed above. Examples of fluidic modulators include without limitation a rotary valve or “mud siren” pressure pulse generator, for example disclosed in U.S. Pat. No. 3,309,656, oscillating valve designs such as disclosed in U.S. Pat. No. 6,626,253, and moveable element pressure pulse generators such as those disclosed in US Publ. Nos. 2015/0034165 A1, 2015/0034385 A1, and 2015/0034386 A1, all of which are incorporated by reference herein in their entireties. The diamond switching mechanism may be used in aggressive environment without sealing a fragile sensor. 
         [0027]      FIGS. 4 and 5  illustrate an example of a diamond switching device  50  operationally connected to a rotational valve  58  utilized in a rotary steerable system  48 . The rotary valve  58  may be selectively rotated to enable flow of fluid (i.e., drilling fluid) and/or to block the flow of the fluid with respect to steering pads  70 . For example, the drilling fluid  20  ( FIG. 2 ) may be delivered through hydraulic lines  72  to act against pistons  74 . During rotation of the drill collar  76  and drill bit  16  for drilling a wellbore, the rotary valve  58  undergoes a controlled, rotation relative to the drill collar to ensure either delivery of the drilling fluid through the hydraulic line  72  to the desired steering pad or blockage of the drilling fluid to the steering pad. As the drill collar rotates, the valve  58  is able to selectively open or shut off pads by allowing the drilling fluid to enter the selected hydraulic lines which correspond to selected pads. Additionally, the rotary valve may be selectively rotated to control other functions, e.g., telemetry functions downhole. For example, the rotary valve  58  may be controlled to cause pressure pulses in the drilling fluid. In some applications, the valve  58  may be used to control other functions unrelated to directional steering. 
         [0028]    The valve  58  (e.g., spider valve) is mounted to a drive shaft  66  in this example which is rotated by an actuator  64 , such as an electric motor. The drive shaft  66  rotates the member  60 , e.g. tool element, relative to member  62  to open, close or otherwise alter opening  86 . A diamond switching device  50  is operatively engaged with the drive shaft  66  to monitor the angular orientation, shown by the arrow  88  in  FIG. 5 , for example relative to the drill collar. The system includes a controller  68  (i.e. processor, electronics). The controller  68  receive data from the diamond switching device  50  and uses the data to control the actuator  64  which, in turn, controls the angular positioning of the rotary valve  58 . Electric power may be provided to the controller  68 , actuator  64 , and to other components via a suitable power source  78 . By way of example, the power source  78  may comprise batteries and/or a turbine  80 . The turbine  80  may comprise an alternator  82  driven by rotation of turbine blades  84  which are rotated by the pressurized flow of the drilling fluid down through the RSS and the drill bit  16 . 
         [0029]    Although a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from the disclosure. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, features shown in individual embodiments referred to above may be used together in combinations other than those which have been shown and described specifically. Accordingly, any such modification is intended to be included within the scope of this disclosure. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not just structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke means-plus-function for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.