1. Field of the Disclosure
This disclosure relates generally to drill bits including sensors for providing measurements for a property of interest of a formation and systems using such drill bits.
2. Brief Description of the Related Art
Oil wells (wellbores or boreholes) are drilled with a drill string that includes a tubular member having a drilling assembly (also referred to as the bottomhole assembly or “BHA”) that has a drill bit attached to the bottom end of the BHA. The drill bit is rotated to disintegrate the earth formations to drill the wellbore. The BHA typically includes devices for providing information about parameters relating to the behavior of the BHA, parameters of the formation surrounding the wellbore and parameters relating to the drilling operations. One such parameter is the rate of penetration (ROP) of the drill bit into the formation.
A high ROP is desirable because it reduces the overall time required for drilling a wellbore. ROP depends on several factors including the design of the drill bit, rotational speed (or rotations per minute or RPM) of the drill bit, weight-on-bit type of the drilling fluid being circulated through the wellbore and the rock formation. A low ROP typically extends the life of the drill bit and the BHA. The drilling operators attempt to control the ROP and other drilling and drill string parameters to obtain a combination of parameters that will provide the most effective drilling environment. ROP is typically determined based on devices disposed in the BHA and at the surface. Such determinations often differ from the actual ROP. Therefore, it is desirable to provide an improved apparatus for determining or estimating the ROP.
In one aspect, a drill bit is disclosed that in one embodiment may include a first sensor positioned on the drill bit configured to provide a first measurement of a parameter at a selected location in a formation at a first time, and a second sensor positioned a selected distance from the first sensor to provide a second measurement of the parameter at the selected location at a second time when the drill bit travels downhole. The drill bit may also include a processor configured to estimate the rate-of-penetration using the selected distance and the first and second times.
In another aspect, a method for estimating a rate-of-penetration of a drill bit in a wellbore is provided that in one embodiment may include: identifying a selected characteristic at a selected location of a formation surrounding a wellbore at a first time using measurements of a first sensor on the drill bit; identifying the selected characteristic at the selected location at a second time using measurements of a second sensor on the drill bit; and estimating the rate-of-penetration for the drill bit based on a distance between the first sensor and second sensor, the first time and the second time.
Examples of certain features of a drill bit having a displacement sensor 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 drill bit and systems for using the same disclosed hereinafter that form the subject of the claims appended hereto.
For detailed understanding of the present disclosure, references should be made to the following detailed description, taken in conjunction with the accompanying drawings in which like elements have generally been designated with like numerals and wherein:
The drill string 118 is shown conveyed into the wellbore 110 from a rig 180 at the surface 167. The rig 180 shown is a land rig for ease of explanation. The apparatus and methods disclosed herein may also be utilized when an offshore rig (not shown) is used. A rotary table 169 or a top drive (not shown) coupled to the drill string 118 may be utilized to rotate the drill string 118 at the surface, which rotates the BHA and thus the drill bit 150 to drill the wellbore 110. A drilling motor 155 (also referred to as “mud motor”) in the drilling assembly may be utilized alone to rotate the drill bit 150 or to superimpose the drill bit rotation by the rotary table 169. A control unit (or “controller”) 190, which may be a computer-based unit, may be placed at the surface for receiving and processing data transmitted by the sensors in the drill bit and BHA 130 and for controlling selected operations of the various devices and sensors in the BHA 130. The surface controller 190, in one embodiment, may include a processor 192, a data storage device (or “computer-readable medium”) 194 for storing data and computer programs 196. The data storage device 194 may be any suitable device, including, but not limited to, a read-only memory (ROM), random-access memory (RAM), flash memory, magnetic tape, hard disk and an optical disk. During drilling, a drilling fluid from a source thereof 179 is pumped under pressure through the tubular member 116, which fluid discharges at the bottom of the drill bit 150 and returns to the surface via the annular space 127 (also referred as the “annulus”) between the drill string 118 and the inside wall of the wellbore 110.
Still referring to
In an aspect, a controller 370 may be positioned on the drill bit 150 to process signals from the sensors 160 and 162 and other sensors in the drill bit. As discussed in detail with reference to
Still referring to
In one aspect, the sensors 260 and 262 may be acoustic sensors using acoustic signals and/or energy for measuring geophysical parameters (e.g., acoustic velocity and acoustic travel time). Further, the sensors 260 and 262 may also detect reflected acoustic waves to identify specific discontinuities in the formation or an acoustic image of the wellbore wall. Illustrative acoustic sensors include acoustic wave sensors that utilize piezoelectric material, magneto-restrictive materials, etc. In addition, each sensor may be a transducer (combination of an acoustic transmitter and acoustic receiver). The transmitter may transmit acoustic signals, such as a signal at high frequency, at a selected wellbore depth and the receiver receives the acoustic waves reflected from the wellbore wall and thus recognizes discontinuities in the formation substantially at the same depth. In other embodiments, the sensors 260 and 262 may measure other parameters, such as resistivity and gamma rays. In another aspect, tracers (magnetic or chemical) may be utilized for determining ROP. Signals from the sensors 260 and 262 may be provided via conductors 240 to a circuit 250 located outside the bit or placed in the drill bit 212b. In one aspect, the circuit 250 may be configured to amplify the signals received from the sensors 260 and 262, digitize the amplified signals and transmit the digitized signals to the controller 370 in the drill bit 200 (
In one embodiment, the sensors 260 and 262 may be acoustic sensors configured to transmit acoustic waves at selected frequencies to the formation surrounding the drill bit 200 and to receive acoustic waves from the formation responsive to the transmitted waves. The acoustic sensors (260, 262) may transmit acoustic waves into a wellbore wall 354 at a frequency, wherein the wall 354 will cause a reflection of the waves back to the sensors (260, 262). The sensors 260 and 262 may receive the reflected waves and the controller 370, 190 and/or 170 determines a characteristic of the borehole wall from the reflected signals. In operation (i.e., while drilling), the acoustic sensor 262 transmits a signal at time T1 at depth 356 and the processor (370, 170 and/or 190) determines a specific characteristic (such as an image of the wall of the borehole or the formation) from the received signals. As the drill bit moves in a downhole direction 360, the sensor 260 continually transmits signals at the same frequency as the sensor 262 and receives the acoustic signals that are processed by the processors. When the drill bit has traveled the distance 264 at time T2, the processors may be able to match the characteristic determined using sensors 262 and 260. Accordingly, the controller and processor can calculate an ROP for the drill bit from the elapsed time (T2-T1) and the known distance 264. For example, if the elapsed time (T2-T1) is 20 seconds and the distance (264) is six inches, the ROP (distance over time: six inches/20 seconds) will be 0.3 inches/second. In other embodiments, as discussed below, the apparatus may use the technique described above with any suitable sensors, such as gamma ray sensors, resistivity sensors, and sensors that detect injected chemical, magnetic or nuclear tracers.
In another embodiment, the sensors 260, 262 may use a gamma ray measurement to calculate ROP for the drill bit. The sensors 260, 262 may be configured to utilize gamma ray spectroscopy to determine the amounts of potassium, uranium and thorium concentrations that naturally occur in a geological formation. Measurements of gamma radiation from these elements may be utilized because such elements are associated with radioactive isotopes that emit gamma radiations at characteristic energies. The amount of each element present within a formation may be determined by its contribution to the gamma ray flux at a given energy. Measuring gamma radiation of these specific element concentrations is known as spectral stripping. Spectral stripping refers to the subtraction of the contribution of unwanted elements within an energy window, including upper and lower boundaries, set to encompass the characteristic energy(s) of the desired element within the gamma ray energy spectrum. Because of these factors, spectral stripping may be accomplished by calibrating the tool initially in an artificial formation with known concentrations of potassium, uranium and thorium under standard conditions.
Illustrative devices for detecting or measuring naturally occurring gamma radiation include magnetic spectrometers, scintillation spectrometers, proportional gas counters and semiconductors with solid state counters. For instance, a suitable gamma ray sensor may utilize a sensor element that includes a scintillation crystal and an optically-coupled photomultiplier tube. Output signals from the photomultiplier tube may be transmitted to a suitable electronics package which may include pre-amplification and amplification circuits. The amplified sensor signals may be transmitted to the processor in a controller. In certain embodiments of the disclosure, solid state devices for gamma ray detection may be utilized.
Gamma ray sensors configured to detect naturally occurring gamma ray sources may provide an indication of a lithology or change in lithology in the vicinity of the bit 200. With reference to
In yet another configuration, the sensors 260 and 262 may be resistivity sensors that provide an image or map of structural features of the formation. The image of selected locations with sensor 262 at time T1 and the same image determined by sensor 260 at time T2 taken the known distance 264 apart may be utilized to determine ROP of the drill bit, as described above with respect to the acoustic signals.
In an aspect, the sealing member 514 and sealing member cavities are sealed from outside pressure by seals 524 and 526 between the sealing member 514 and circular piece 512. The seals 524 and 526 may be any suitable sealing mechanism, such as an O-ring composed of a rubber, silicone, plastic or other durable sealing composite material. The seals 524 and 526 may be configured to seal the sealing member 514 from up to 20,000 pounds-per-square-inch (psi) of downhole pressure outside the drill bit. Due to the configuration of sealing member 514 and seals 524 and 526, electronic components are protected within the depressurized environment within the sealed area. For example, a controller 570 may be positioned within the sealed portion of the sealing member 514 to process signals from the sensors used to calculate the ROP. The controller 570 may include a processor 572, a data storage device 574 and programs 576 for use by the processor 572 to process downhole data and to communicate with the surface controller 190 (
The foregoing description is directed to certain embodiments for the purpose of illustration and explanation. It will be apparent, however, to persons skilled in the art that many modifications and changes to the embodiments set forth above may be made without departing from the scope and spirit of the concepts and embodiments disclosed herein. It is intended that the following claims be interpreted to embrace all such modifications and changes.
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Number | Date | Country | |
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