Patent Grant
11668185
Drilling a borehole to penetrate a hydrocarbon reservoir is a critical procedure in discovering, evaluating and producing oil and gas. It is common practice to extend the length a borehole by causing a drill bit to rotate while in contact with the rock at the bottom of the borehole. The drill bit typically consists of a plurality of cutters embedded in a plurality of blades arranged over the surface of the drill bit. During drilling the cutters become worn and their efficiency in extending the length of the borehole becomes diminished. Replacing the drill bit is time consuming and expensive and consequently it is undesirable to replace the drill bit sooner or more frequently than essential.
Thus, it is advantageous to have means of monitoring the wear of the cutters and the ability to correlate the wear and rate of wear of the cutters with other drilling parameters. This knowledge may be used to modify the drilling parameters during drilling and to modify the design and construction of future drill bits.
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 the claimed subject matter.
In general, in one aspect, embodiments relate to an instrumented cutter including a polycrystalline diamond table bonded to a substrate with a sensor, for monitoring the condition of the polycrystalline compact diamond table, embedded in the substrate. Further the instrumented cutter includes a wireless transmitter equipped with a power supply to power to the wireless transmitter.
In general, in one aspect, embodiments relate to a system including a string of drill-pipe, suspended from a drilling rig and attached to a bottomhole assembly and a drill bit, for boring a borehole in a rock formation. At least one instrumented cutter containing a sensor is mounted in a blade of the drill bit.
In general, in one aspect, embodiments relate to a method including inserting at least one instrumented cutter into a blade of a drill bit and attaching the drill bit to a bottomhole assembly. Further, the method includes inserting the drill bit and bottomhole assembly attached by a drill string to a drilling rig, into a borehole. The method still further includes increasing the size of the borehole by rotating the drill bit, transmitting a datum from the at least one instrumented cutter to the drilling rig; and modifying at least one parameter of drilling based, at least in part, on the datum from the at least one instrumented cutter. Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.
Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency.
In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.
Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.
Embodiments disclosed herein relate to an instrumented polycrystalline diamond compact (PDC) cutter mounted in at least one blade of a drill bit. An instrumented PDC cutter is a PDC cutter in which at least one sensor has been embedded. In addition, a source of power, a non-transitory computer memory module, a wireless transceiver and an electronic control module may be embedded in the instrumented PDF cutter to store and transmit the measurements made by sensor. The sensor may make measurements to monitor the state of wear of the cutting surface of the instrumented PDC cutter and these measurements may be store for later retrieval or transmitted to the drilling rig. Modifications to the drilling parameters, including weight on bit, torque, and the time to replace the bit may be made in real-time, or near real-time based at least in part on the measurements. Further, modifications to parameters describing the drill bit design may be made.
In addition, embodiments disclosed herein are directed to a new sensing logging method for monitoring the real-time condition of the PDC cutters in the drill bit by forming an intelligent logging system inside PDC cutter substrates through measuring electrical, capacitive, acoustic, magnetic or other field properties. Data from the sensors may be transferred to the data processing system for drilling optimization and drilling automation. The on-cutter sensing technology of the instrumented PDC cutter has the ability to measure individual PDC cutter wear conditions that permit more accurate correlation of PDC cutter damage reduction to specific bit features and improving iterative improvements. Embodiments disclosed herein also aid in predicting bit performance based on the measurements that may be used to tailor drilling automation algorithms to optimize drilling performance based on current cutter/bit condition.
Moreover, when completing a well, casing may be inserted into the borehole (116). The sides of the borehole (116) may require support, and thus the casing may be used for supporting the sides of the borehole (116). As such, a space between the casing and the untreated sides of the borehole (116) may be cemented to hold the casing in place. The cement may be forced through a lower end of the casing and into an annulus between the casing and a wall of the borehole (116).
As further shown in
In accordance with one or more embodiments, a telemetry transceiver (130B) may be installed in the BHA (123) of a drilling system (100) to transmit data and signals through a telemetry channel (132) from the BHA (123) to a telemetry transceiver (130A) located on the drilling rig (102). The telemetry channel (132) may use acoustic signals transmitted through the drilling fluid. In other embodiments, the telemetry channel (132) may use electromagnetic signals transmitted through wired drill pipe. In other embodiments, the telemetry channel (132) may use electromagnetic signals transmitted through the geologic formations to the transceiver (130A) at the Earth's surface (104). The data and signals transmitted through the telemetry channel (132) may be processed and analyzed to determine by a computer system (134). The computer system (134) may be located on the drilling rig (102) or at a remote location.
The computer system (134) may be coupled to the drilling rig (102) in order to perform various functions for extending the length of the borehole (116), such as changing the rotational speed of the drill bit (124) and changing the force applied to the drill bit (124).
In accordance with one or more embodiments, the cutting structure which is provided on the drill bit (200) includes six angularly spaced apart blades (212). In some embodiments, these blades (212) may be identical to each other, and in other embodiments these blades (212) may include a plurality of different blade types or designs. These blades (212) each project from the bit body (202) and extend radially out from the axis (210). The blades (212) are separated by channels that are sometimes referred to as junk slot (214) or flow courses. The junk slots (214) allow for the flow of drilling fluid supplied down the drill string (115) and delivered through apertures (216), which may be referred to as nozzles or ports. Flow of drilling fluid cools the PDC cutters and as the flow moves uphole, carries away the drilling cuttings from the face of the drill bit (200). Those skilled in the art will appreciate that while
In accordance with one or more embodiments, the blades (212) have pockets or other types of cavities which extend inwardly from open ends that face in the direction of rotation (210). PDC cutters (220) are secured by brazing in these cavities formed in the blades (212) so as to rotationally lead the blades and project from the blades, which exposes the diamond cutting faces of the PDC cutters as shown. According to one or more embodiments, the number of cutters (220) on each blade (212) may be identical; alternatively, the number of cutters (220) may be different on some blades (212) from other blades (212). Similarly, according to one or more embodiments, the position of cutters (220) on each blade (212) may be identical or may be different on some blades (212) from other blades (212).
Continuing with
In accordance with one or more embodiments, at least one of the PDC cutters is an instrumented PDC cutter (330). An instrumented PDC cutter (330) differs from a non-instrumented PDC cutter (320) in that an instrumented PDC cutter (330) may contain at least one sensor to monitor the state of wear of the instrumented PDC cutters (330). In accordance with some embodiments, the instrumented PDC cutters (330) may be located at key locations anticipated by the operators to be locations at which the PDC cutters (330) may experience a maximum rate of wear. In accordance with one or more embodiments, the instrumented PDC cutters (330) may be positioned at the same position on each blade (312). In accordance with other embodiments, the instrumented PDC cutters (330) may be positioned at different locations on each blade (312). In accordance with still other embodiments, all the PDC cutters (320) in drill bit (300) may be instrumented PDC cutters (330).
A second sensor (442) may be embedded in the substrate (436) of the instrumented PDC cutter (430). The second sensor (442) may be configured to remotely sense or remotely monitor wear of the cutting surface (434). Although
In particular, each of the plurality of first sensors (440) may use a different sensing modality. For example, one member of a plurality of first sensors (440) may be sensitive to electrical capacitance, and a second member of a plurality of second sensors (440) may be sensitive to ultrasonic propagation time. Similarly, each of the plurality of second sensors (442) may use a different sensing modality. For example, one member of a plurality of second sensors (442) may be sensitive to electrical capacitance, and a second member of a plurality of second sensors (442) may be sensitive to ultrasonic propagation time. Further a first sensor (440) embedded in the PDC diamond table (432) may use a sensing modality different from a second sensor (442) embedded in the substrate (436) of the instrumented PDC cutter (430).
In accordance with one or more embodiments,
In accordance with one or more embodiments,
Although
Just as the resistivity sensor (540) shown in
Initially, in Step 702, at least one instrumented PDC cutter (330) is inserted into at least one blade (312) of a drill bit (300). The instrumented PDC cutter (430) may include at least one sensor (440, 442), that may be configured to monitor the wear of the cutting surface (434) of the instrumented PDC cutter (430). In accordance with other embodiments, each blade (312) may be equipped with a plurality of instrumented cutters (430). The instrumented PDC cutter (430) may be differ in design from one another and may use different physical sensing modalities.
In Step 704 the drill bit (300) and BHA (123) may be inserted into a borehole (116) attached to a drill string (115) extending from the BHA (123) to a drilling rig (102). The drill string (115) may include a plurality of joints of drill pipe, a plurality of joints of wired drill pipe, or a coiled tubing, in accordance with one or more embodiments. The insertion of the drill bit (300), BHA (123), and drill string (115) may comprise suspending the drill bit (300), BHA (123), and drill string (115) from the drilling rig (102).
In Step 706, in accordance with one or more embodiments, the size of the borehole (116) may be increased by rotation of the drill bit (300). The rotation of the drill bit (300) may be caused by the rotation of the drill string (115) that is, in turn, caused by the rotation of equipment on the drilling rig (102). In accordance with other embodiments, the rotation of the drill bit (300) may be caused by the rotation of a mud-motor, or electrical motor mounted in the BHA (123). The size of the borehole increases, at least in part, by the abrasion of one or more instrumented PDC cutters (430) against the rock formation (125). In accordance with one or more embodiments, the increase in size of the borehole (116) may be an increase in the length of the borehole (116). In accordance with other embodiments, the increase in size of the borehole (116) may be an increase in the diameter of the borehole (116) or may be a simultaneous increase in both the length and the diameter of the borehole (116).
In Step 708, in accordance with one or more embodiments, at least one measurement may be made of the wear of the cutting surface (434) of an instrumented PDC cutter (430) by at least one sensor (440, 442) embedded in the PDC diamond table (432), or the substrate (436) of the instrumented PDC cutter (430). The measurement may be based upon the following without limitation, a strain, an acceleration, a motion, a vibration, an image, an electrical resistance, an electrical capacitance, an electrical inductance, a magnetic field, and a photoelectric emission, alone or in combination with one another.
In accordance with one or more embodiments, in Step 710 at least one measurement may be transmitted from the instrumented PDC cutter (430) to the BHA (123). The transmission of at least one measurement from the instrumented PDC cutter (430) to the BHA (123) may be performed using at least one wireless transceiver selected from the group composed of a Wi-Fi transceiver, a Bluetooth transceiver, an induction wireless transceiver, an infrared wireless transceiver, an ultra-wideband transceiver, a ZigBee transceiver, or an ultrasonic transceiver, and from the BHA to the drilling rig.
In Step 712, in accordance with one or more embodiment, at least one measurement may be transmitted from the BHA (123) to the drilling rig (102). The transmission of at least one measurement may be performed using mud-pulse telemetry, wired drill pipe telemetry, wired coiled tubing telemetry, or electromagnetic induction telemetry.
In accordance with one or more embodiments, in Step 718, at least one drilling parameter may be modified based, at least in part, on at least one measurement from the instrumented PDC cutter (430). The modified drilling parameter(s) may include, without limitation, a weight on bit (WOB), a drilling direction, a mud weight, torque on bit, and many other drilling parameters. The modification of one or more drilling parameters may be performed in real-time. The modification may be commanded by an operator based, at least in part, on inspection of the measurement and/or change in the measurement. The modification may be commanded or performed by a drilling automation algorithm based, at least in part, on the measurement and/or a change in the measurement. The measurement may further allow the operator to determine the grade of the PDC cutter and the bit composed of a plurality of cutters, including how “dull” or worn are the plurality of PDC cutters.
The modification of drilling parameters may include the time at which it is optimal to replace the bit, including the retraction of the drill string (115), the BHA (123), and the drill bit (124) from the borehole (102); the replacements if the drill bit (124) with a new and unworn drill bit (124), and the insertion of the drill string (115), the BHA (123), and the drill bit (124) into the borehole (102).
In accordance with one or more embodiments, in Step 714 at least one measurement may be stored in the non-transient computer memory module (546, 646) embedded in the instrumented PDC cutter (530, 630). In Step 716, in accordance with one or more embodiment, at least one measurement from the non-transient computer memory module (546, 646) embedded in the instrumented PDC cutter (530, 630) may be read. The non-transient computer memory module (546, 646) may be read when the drill bit (300), BHA (123) and drill string (115) is retracted from the borehole (102). In accordance with other embodiments, the modified parameter may be a parameter describing the design of a drilling bit (300), or the design of a PDC cutter (320). In accordance with other embodiments, the modified parameters may be control parameters in drilling automation algorithms which perform the automatic control of drilling parameters, and predict the current and future performance of the drill bit (300).
Although only 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 this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, any means-plus-function clauses are intended to cover the structures described herein as performing the recited function(s) and equivalents of those structures. Similarly, any step-plus-function clauses in the claims are intended to cover the acts described here as performing the recited function(s) and equivalents of those acts. It is the express intention of the applicant not to invoke 35 U.S.C. § 112(f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the words “means for” or “step for” together with an associated function.
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