Patent Application
20130048381
The present disclosure relates generally to earth-boring drill bits carrying data acquisition systems. More particularly, embodiments of the present disclosure relate to facilitating data transfer from a data acquisition system mounted in a drill bit to a sub above the drill bit.
The oil and gas industry expends sizable sums to design cutting tools, such as downhole drill bits including roller cone rock bits and fixed cutter bits, which have relatively long service lives, with relatively infrequent failure. In particular, considerable sums are expended to design and manufacture roller cone rock bits and fixed cutter bits in a manner that minimizes the opportunity for catastrophic drill bit failure during drilling operations. The loss of a roller cone or a polycrystalline diamond compact (PDC) cutter from a fixed cutter bit during drilling operations can impede the drilling operations and, at worst, necessitate rather expensive fishing operations. If the fishing operations fail, sidetrack-drilling operations must be performed in order to drill around the portion of the wellbore that includes the lost roller cones or PDC cutters. Thus, during drilling operations, bits are pulled and replaced with new bits out of an abundance of caution, even though significant service could still be obtained from the replaced bit. These premature replacements of downhole drill bits are expensive, since each trip out of the well prolongs the overall drilling activity, and consumes considerable manpower, but are nevertheless done in order to avoid the far more disruptive and expensive process of, at best, pulling the drill string and replacing the bit or fishing and sidetrack drilling operations necessary if one or more cones or PDC cutters are lost due to bit failure.
In response to the ever-increasing need for downhole drilling system dynamic data, a number of “subs” (i.e., a sub-assembly incorporated into the drill string above the drill bit and used to collect data relating to drilling parameters) have been designed and installed in drill strings. Unfortunately, these subs cannot provide actual data for what is happening operationally at the bit due to their physical placement above the bit itself.
Data acquisition is conventionally accomplished by mounting a sub in the bottom hole assembly (BHA), which may be several feet to tens of feet away from the bit. Data gathered from a sub this far away from the bit may not accurately reflect what is happening directly at the bit while drilling occurs. Often, this lack of data leads to conjecture as to what may have caused a bit to fail or why a bit performed so well, with no directly relevant facts or data to correlate to the performance of the bit.
Recently, data acquisition systems have been proposed to install in the drill bit itself. For example, Baker Hughes Incorporated, assignee of the present invention, has developed a data acquisition system marketed under the trademark DATABIT®, embodiment of which are disclosed and claimed in U.S. Pat. No. 7,604,072; U.S. Pat. No. 7,497,276; U.S. Pat. No. 7,506,695; U.S. Pat. No. 7,510,026; and U.S. Pat. No. 7,849,934, each of which is assigned to the assignee of the present invention, and the disclosure of each of which is incorporated by reference herein in its entirety.
However, data reporting from these systems has been limited. Specifically, real-time data retrieval from a bit-mounted data acquisition system has been unavailable due to the lack of a robust technique for transferring data from the drill bit to the surface. As a consequence, data from such systems is, conventionally, only accessible when the drill bit has been tripped out of the well bore and the data acquisition system retrieved from the drill bit for data download. Such an approach limits the usefulness of information to the operator, who does not become aware of issues that may, if they could be addressed substantially in real time, enhance drilling performance and minimize the potential for damage to the drill bit.
The present disclosure includes a drill bit and a data acquisition system disposed within the drill bit and configured for transfer of data sampled by the system from physical parameters related to drill bit performance.
In one embodiment of the invention, a data acquisition module comprises a housing having a longitudinal bore therethrough and including a base configured for disposition within a bore of drill bit shank and an extension having electrical contacts disposed on an exterior surface thereof.
In another embodiment, a drill bit for drilling a subterranean formation comprises a bit body, a shank secured to the bit body, and a data acquisition module having a longitudinal bore and comprising base disposed within a bore of the shank and an extension protruding from the base beyond the shank and carrying electrical contacts on a peripheral exterior surface thereof.
In a further embodiment, a bottom hole assembly includes a sub comprising electrical contacts on an interior surface thereof operably coupled to electrical contacts on an exterior surface of a portion of a data acquisition module extending into the sub from a base received within a bore of a drill bit shank.
In yet another embodiment, a method of transferring data comprises acquiring data from at least one sensor carried by a drill bit and transferring the acquired data from at least a location within a shank of the drill bit through at least one physical data transfer path to an interior surface of a sub to which the shank is secured.
In the following detailed description, reference is made to the accompanying drawings that form a part hereof and, in which are shown by way of illustration, specific embodiments in which the invention may be practiced. These embodiments are described in sufficient detail to enable those of ordinary skill in the art to practice the invention, and it is to be understood that other embodiments may be utilized, and that structural, logical, and electrical changes may be made within the scope of the disclosure.
In this description, specific implementations are shown and described only as examples and should not be construed as the only way to implement the present invention unless specified otherwise herein. It will be readily apparent to one of ordinary skill in the art that the various embodiments of the present disclosure may be practiced by other partitioning solutions.
Referring in general to the following description and accompanying drawings, various embodiments of the present disclosure are illustrated to show its structure and method of operation. Common elements of the illustrated embodiments may be designated with similar reference numerals. It should be understood that the figures presented are not meant to be illustrative of actual views of any particular portion of the actual structure or method, but are merely idealized representations employed to more clearly and fully depict the present invention defined by the claims below. The illustrated figures may not be drawn to scale.
During drilling operations, drilling fluid is circulated from a mud pit 160 through a mud pump 162, through a desurger 164, and through a mud supply line 166 into the swivel 120. The drilling mud (also referred to as drilling fluid) flows through the Kelly joint 122 and into an axial bore in the drill string 140. Eventually, it exits through apertures or nozzles, which are located in a drill bit 200, which is connected to the lowermost portion of the drill string 140 below drill collar section 144. The drilling mud flows back up through an annular space between the outer surface of the drillstring 140 and the inner surface of the borehole 100, to be circulated to the surface where it is returned to the mud pit 160 through a mud return line 168.
A shaker screen (not shown) may be used to separate formation cuttings from the drilling mud before it returns to the mud pit 160. The communication system 146 may utilize a mud pulse telemetry technique to communicate data from a downhole location to the surface while drilling operations take place. To receive data at the surface, a mud pulse transducer 170 is provided in communication with the mud supply line 166. This mud pulse transducer 170 generates electrical signals in response to pressure variations of the drilling mud in the mud supply line 166. These electrical signals are transmitted by a surface conductor 172 to a surface electronic processing system 180, which is conventionally a data processing system with a central processing unit for executing program instructions, and for responding to user commands entered through either a keyboard or a graphical pointing device. The mud pulse telemetry system is provided for communicating data to the surface concerning numerous downhole conditions sensed by well logging and measurement systems that are conventionally located within the communication system 146. Mud pulses that define the data propagated to the surface are produced by equipment conventionally located within the communication system 146. Such equipment typically comprises a pressure pulse generator operating under control of electronics contained in an instrument housing to allow drilling mud to vent through an orifice extending through the drill collar wall. Each time the pressure pulse generator causes such venting, a negative pressure pulse is transmitted to be received by the mud pulse transducer 170. An alternative conventional arrangement generates and transmits positive pressure pulses. As is conventional, the circulating drilling mud also may provide a source of energy for a turbine-driven generator subassembly (not shown) which may be located near a bottom hole assembly (BHA). The turbine-driven generator may generate electrical power for the pressure pulse generator and for various circuits including those circuits that form the operational components of the measurement-while-drilling tools. As an alternative or supplemental source of electrical power, batteries may be provided, particularly as a backup for the turbine-driven generator.
A plurality of gage inserts 235 are provided on the gage pad surfaces 230 of the drill bit 200. Shear cutting gage inserts 235 on the gage pad surfaces 230 of the drill bit 200 provide the ability to actively shear formation material at the sidewall of the borehole 100 and to provide improved gage-holding ability in earth-boring bits of the fixed cutter variety. The drill bit 200 is illustrated as a PDC (“polycrystalline diamond compact”) bit, but the gage inserts 235 may be equally useful in other fixed cutter or drag bits that include gage pad surfaces 230 for engagement with the sidewall of the borehole 100.
Those of ordinary skill in the art will recognize that the present invention may be embodied in a variety of drill bit types. The present invention possesses utility in the context of a tricone, also characterized as or roller cone, rotary drill bit or other subterranean drilling tools as known in the art that may employ nozzles for delivering drilling mud to a cutting structure during use. Accordingly, as used herein, the term “drill bit” includes and encompasses any and all rotary bits, including core bits, roller cone bits, fixed cutter bits; including PDC, natural diamond, thermally stable produced (TSP) synthetic diamond, and diamond impregnated bits without limitation, hybrid bits including both fixed and movable cutting structures, eccentric bits, bicenter bits, reamers, reamer wings, as well as other earth-boring tools configured for acceptance of an electronics module 290 (
The base B of data acquisition module 270 includes a longitudinal bore 276 formed therethrough, such that the drilling mud may flow through the data acquisition module 270, through the bore 280 of the shank 210 to the other side of the shank 210, and then into the body of drill bit 200. In addition, the base B of data acquisition module 270 includes a first flange 271 including a first sealing ring 272, protruding laterally from base body 275 near the lower end of the base B, and a longitudinally separated second flange 273 including a second sealing ring 274 protruding laterally from base body 275, near the upper end of the base B of data acquisition module 270 to create a fluid tight annular chamber 260 (
In the embodiment shown in
An electronics module 290 configured as shown in the embodiment of
A functional block diagram of an embodiment of a data acquisition system 300 configurable according to an embodiment of the disclosure and including a data acquisition module 270 including electronics module 290 is illustrated in
The plurality of accelerometers 340A may include three accelerometers 340A configured in a Cartesian coordinate arrangement. Similarly, the plurality of magnetometers 340M may include three magnetometers 340M configured in a Cartesian coordinate arrangement. While any coordinate system may be defined within the scope of the present invention, an exemplary Cartesian coordinate system, shown in
The accelerometers 340A of the
The magnetometers 340M of the
The temperature sensor 340T may be used to gather data relating to the temperature of the drill bit 200, and the temperature near the accelerometers 340A, magnetometers 340M, and other sensors 340. Temperature data may be useful for calibrating the accelerometers 340A and magnetometers 340M to be more accurate at a variety of temperatures.
Other optional sensors 340 may be included as part of the data acquisition module 270. Examples of sensors that may be useful in the present invention are strain sensors at various locations of the drill bit, temperature sensors at various locations of the drill bit, mud (drilling fluid) pressure sensors to measure mud pressure internal to the drill bit, and borehole pressure sensors to measure hydrostatic pressure external to the drill bit. These optional sensors 340 may include sensors 340 that are integrated with and configured as part of the data acquisition module 300. These sensors 340 may also include optional remote sensors 340 placed in other areas of the drill bit 200, or above the drill bit 200 in the bottom hole assembly. The optional sensors 340 may communicate using a direct-wired connection, or through an optional sensor receiver 360. The sensor receiver 360 is configured to enable wireless remote sensor communication 362 across limited distances in a drilling environment as are known by those of ordinary skill in the art.
One or more of these optional sensors may be used as an initiation sensor 370. The initiation sensor 370 may be configured for detecting at least one initiation parameter, such as, for example, turbidity of the mud, and generating a power enable signal 372 responsive to the at least one initiation parameter. A power gating module 374 coupled between the power supply 310, and the data acquisition module 300 may be used to control the application of power to the data acquisition module 300 when the power enable signal 372 is asserted. The initiation sensor 370 may have its own independent power source, such as a small battery, for powering the initiation sensor 370 during times when the data acquisition module 300 is not powered. As with the other optional sensors 340, some examples of parameter sensors that may be used for enabling power to the data acquisition module 300 are sensors configured to sample; strain at various locations of the drill bit, temperature at various locations of the drill bit, vibration, acceleration, centripetal acceleration, fluid pressure internal to the drill bit, fluid pressure external to the drill bit, fluid flow in the drill bit, fluid impedance, and fluid turbidity. In addition, at least some of these sensors may be configured to generate any required power for operation such that the independent power source is self-generated in the sensor. By way of example, and not limitation, a vibration sensor may generate sufficient power to sense the vibration and transmit the power enable signal 372 simply from the mechanical vibration.
The memory 330 may be used for storing sensor data, signal processing results, long-term data storage, and computer instructions for execution by the processor 320. Portions of the memory 330 may be located external to the processor 320 and portions may be located within the processor 320. The memory 330 may be Dynamic Random Access Memory (DRAM), Static Random Access Memory (SRAM), Read Only Memory (ROM), Nonvolatile Random Access Memory (NVRAM), such as Flash memory, Electrically Erasable Programmable ROM (EEPROM), or combinations thereof. In the
A communication port 350 may be included in the data acquisition module 270 for communication to external devices such as the communication system 146 and a remote processing system 390. The communication port 350 may be configured for a direct communication link 352 to the remote processing system 390 using a direct wire connection or a wireless communication protocol, such as, by way of example only, infrared, Bluetooth, and 802.11a/b/g protocols. Using the direct communication, the data acquisition module 270 may be configured to communicate with a remote processing system 390 such as, for example, a computer, a portable computer, and a personal digital assistant (PDA) when the drill bit 200 is not downhole. Thus, the direct communication link 352 may be used for a variety of functions, such as, for example, to download software and software upgrades, to enable setup of the data acquisition module 300 by downloading configuration data, and to upload sample data and acquisition data. The communication port 350 may also be used to query the data acquisition module 270 for information related to the drill bit, such as, for example, bit serial number, data acquisition module serial number, software version, total elapsed time of bit operation, and other long term drill bit data which may be stored in the NVRAM.
The communication port 350 may also be configured for communication with the communication system 146 in a bottom hole assembly via a communication link 354 according to the present disclosure. The communication system 146 may, in turn, communicate data from the data acquisition module 270 to a remote processing system 390 using mud pulse telemetry 356 or other suitable communication means suitable for communication across the relatively large distances encountered in a drilling operation.
The processor 320 in the embodiment of
The embodiment of
The embodiment of
Although the foregoing description contains many specifics, these are not to be construed as limiting the scope of the present disclosure, but merely as providing certain embodiments. Similarly, other embodiments of the disclosure may be devised that do not depart from the scope of the present invention. For example, features described herein with reference to one embodiment also may be provided in others of the embodiments described herein. The scope of the invention is, therefore, indicated and limited only by the appended claims and their legal equivalents, rather than by the foregoing description. All additions, deletions, and modifications to the invention, as disclosed herein, which fall within the meaning and scope of the claims, are encompassed by the present invention.
