Patent Grant
11078772
A portion of the disclosure of this patent document contains material which is subject to copyright protection. The copyright owner has no objection to the facsimile reproduction by anyone of the patent document or the patent disclosure, as it appears in the Patent and Trademark Office patent file or records, but otherwise reserves all copyright rights whatsoever.
The present disclosure relates to a drilling system for forming a borehole in an earthen formation, and in particular to a drilling system and a method for monitoring drilling parameters for an underground drilling operation.
Underground drilling, such as gas, oil, or geothermal drilling, generally involves drilling a bore through a formation deep in the earth. Such bores are formed by connecting a drill bit to long sections of pipe, referred to as a “drill pipe,” so as to form an assembly commonly referred to as a “drill string.” The drill string extends from the surface to the bottom of the bore. The drill bit is rotated so that the drill bit advances into the earth, thereby forming the bore. In rotary drilling, the drill bit is rotated by rotating the drill string at the surface. A mud motor can be used to rotate the drill bit as is known. In general, optimal drilling is obtained when the rate of penetration (“ROP”) of the drill bit into the formation is as high as possible while vibration of the drilling system is as low as possible. Rate of penetration is a function of a number of variables, including the rotational speed of the drill bit and the weight-on-bit (“WOB”). The drilling environment, and especially hard rock drilling, can induce substantial vibration and shock into the drill string, which has an adverse impact on drilling performance. Vibration is introduced by rotation of the drill bit, the motors used to rotate the drill bit, the pumping of drilling mud, and imbalance in the drill string, etc. Vibration can cause premature failure of the various components of the drill string, premature dulling of the drill bit, or may cause the catastrophic failures of drilling system components. Optimal drilling should account for the vibration of the drilling system and the impact such vibration can have on various operating parameters or drill string components. The drilling environment, as well as vibration of the drilling system during a drilling operation, can make it difficult for a drill rig operator to ensure that drilling parameters are operating as expected or optimally.
An embodiment of the present disclosure is a drilling system for forming a borehole in an earthen formation. The drilling system can include a drill string configured to rotate so as to form the borehole in an earthen formation during a drilling operation. The drill string can operate according to one or one or more drilling parameters so as to form the borehole. The drilling system can include a plurality of sensors configured to obtain drilling data during the drilling operation, the drilling data being indicative of the one more drilling parameters, at least one of the plurality of sensors supported by the drill string. The drilling system can also include a computing device configured to determine a first plurality of operating ranges for the one or more drilling parameters of the drilling operation based on the drilling data obtained from the plurality of sensors. The first plurality of operating ranges can be based on a first duration of time operating the drill string during the drilling operation. The first plurality of operating ranges include at least one preferred operating range for each of the one or more drilling parameters and at least one less preferred operating range for each of the one or more drilling parameters. The computing device can also be configured to determine a second, updated plurality of operating ranges for the one or more drilling parameters. The second, updated plurality of operating ranges based on a second duration of time operating the drill string that is subsequent to the first duration of time, the second, updated plurality of operating ranges include at least one preferred operating range and at least one less preferred operating range for each of the one or more drilling parameters. The at least one preferred operating range of the second, updated plurality of operating ranges can be different than the at least one preferred operating range for the first plurality of operating ranges. The computing device can include a user interface, such as graphical user interface, that is configured to display on a computer display a visual indication of the first plurality of operating ranges for the one or more drilling parameters The user interface is configured to display subsequent to the first duration of time, a visual indication of the second, updated plurality of operating ranges for the one or more drilling parameters.
Another embodiment of the present disclosure is a computer implemented method, system and a non-transitory, tangible computer readable medium for monitoring and displaying one or more drilling parameters for a drill string operating to form a borehole in an earthen formation. The method includes determining, via a computer processor, a first plurality of operating ranges for the one or more drilling parameters for a drilling operation. The first plurality of operating ranges can be based on a first duration of time operating the drill string during the drilling operation. The first plurality of operating ranges include at least one preferred operating range for each of the one or more drilling parameters and at least one less preferred operating range for each of the one or more drilling parameters. In response to the step of determining the first plurality of operating ranges by the computer processor, the method can include displaying, via a graphical user interface on a computer display, a visual indication of the first plurality of operating ranges for the one or more drilling parameters. The method includes determining, via the computer processor, a second, updated plurality of operating ranges for the one or more drilling parameters. The second, updated plurality of operating ranges can be based on a second duration of time operating the drill string that is subsequent to the first duration of time. The second, updated plurality of operating ranges include at least one preferred operating range and at least one less preferred operating range for each of the one or more drilling parameters. The at least one preferred operating range of the second, updated plurality of operating ranges can be different than the at least one preferred operating range for the first plurality of operating ranges. In response to the step of determining the second, updated plurality of operating ranges, the method can display, via the graphical user interface on the computer display, the second, updated plurality of operating ranges the one or more drilling operation parameters.
The foregoing summary, as well as the following detailed description of illustrative embodiments of the present application, will be better understood when read in conjunction with the appended drawings. For the purposes of illustrating the present application, there is shown in the drawings illustrative embodiments. It should be understood, however, that the application is not limited to the precise arrangements and instrumentalities shown. In the drawings:
Referring to
Continuing with
A drilling operation as used herein refers to one or more drill runs that define the borehole 2. For instance a drilling operation can include a first drill run for defining a vertical section of the borehole 2, a second drill run for defining a bent section of the borehole 2, and a third drill run for defining a horizontal section of the borehole 2. More or less than three drill runs are possible. For difficult drilling operations, as much as 10 to 15 drill runs may be completed to define the borehole 2 for hydrocarbon extraction purposes. It should be appreciated that one or more bottomhole assemblies can be used for each respective drill run. The systems, methods, software applications as described herein can be used to execute methods that monitor and control the drilling operation, as well as monitor and control the specific drilling runs in the drilling operation.
In the illustrated embodiment the computing device 100 is configured to cause the display of a visual indication of a plurality of operating ranges for each of the drilling parameters and to update the display as the drilling operation progresses. As will be further detailed bellow, the computing device 100 can cause the display of an operation set point or target for a particular drilling parameter, a preferred operating range, less preferred operating range, and a least preferred or critical operating range. Because the computing device 100 can cause the display of a visual indication of the ranges of operating parameters, a user can observe the effect of adjusting one drilling parameter on another drilling parameter during the course of the drilling operation.
Referring to
Continuing with
Further, the bottomhole assembly sensors can also include at least one magnetometer 42. The magnetometer is configured to measure the instantaneous rotational speed of the drill bit 8, using, for example, the techniques in U.S. Pat. No. 7,681,663, entitled “Methods And Systems For Determining Angular Orientation Of A Drill String,” hereby incorporated by reference herein in its entirety. The bottomhole assembly sensors can also include accelerometers 44, oriented along the x, y, and z axes (not shown) (typically with ±250 g range) that are configured to measure axial and lateral vibration. While accelerometer 44 is shown disposed on the bottomhole assembly 6, it should be appreciated that multiple accelerometers 44 can be installed at various locations along the drill string 4, such that axial and lateral vibration information at various locations along the drill string can be measured.
As noted above, the bottomhole assembly 6 includes a vibration analysis system 46. The vibration analysis system 46 is configured to receive data from the accelerometers 44 concerning axial, lateral, and torsional vibration of the drill string 4. Based on the data received from the accelerometers, the vibration analysis system 46 can determine the measured amplitude and frequency of axial vibration, and of lateral vibration due to forward and backward whirl, at the location of the accelerometers on the drill string 4. The measured amplitude and frequency of axial and lateral vibration can be referred to as measured vibration information. The measured vibration information can also be transmitted to the surface 11 and processed by the computing device 100. The vibration analysis system 46 can also receive data from the magnetometer 42 concerning the instantaneous rotational speed of the drill string at the magnetometer 42 location. The vibration analysis system 46 then determines the amplitude and frequency of torsional vibration due to stick-slip. The measured frequency and amplitude of the actual torsional vibration is determined by calculating the difference between and maximum and minimum instantaneous rotational speed of the drill string over a given period of time. Thus, the measured vibration information can also include measured torsional vibration.
The bottomhole assembly sensors can also include at least a first and second pressure sensors 51 and 52 that measure the pressure of the drilling mud flowing through drilling system components in the borehole 2. For instance, the first and second sensors 51 and 52 measure pressure of the drilling mud flowing through the drill string 4 (in a downhole direction), and the pressure of the drilling mud flowing through the annular gap between the borehole wall and the drill string 4 in an uphole direction, respectively. Differential pressure is referred to as the difference in pressure between the drilling mud flowing in the downhole direction and the drilling mud flowing in the up-hole direction. Pressure information can be transmitted to the computing device 100.
Further, the drilling system 1 can also include one or more sensors disposed at the surface, for instance on the derrick 9. For instance, the drilling system can include a hook load sensor 30 for determining WOB and an additional sensor 32 for sensing drill string rotational speed of the drill string 4. The hook load sensor 30 measures the hanging weight of the drill string, for example, by measuring the tension in a draw works cable (not numbered) using a strain gauge. The cable is run through three supports and the supports put a known lateral displacement on the cable. The strain gauge measures the amount of lateral strain due to the tension in the cable, which is then used to calculate the axial load and WOB.
The drilling system 1 can also include a drilling data acquisition system 12 that is in electronic communication with the computing device 100. The drilling data acquisition system 12 is configured to receive, process and store data that has been obtained from the various downhole and surface sensors described above. Accordingly, various systems and methods for transmitting can be used to transmit data between drill string components and the drilling data acquisition system 12. For instance, in a wired pipe implementation, the data from the bottomhole assembly sensors is transmitted to the top sub 45. The data from the top sub 45 sensors, as well as data from the bottomhole assembly sensors in a wired pipe system, can be transmitted to the drilling data acquisition system 12 and/or computing device 100 using wireless telemetry. One such method for wireless telemetry is disclosed in U.S. application Ser. No. 12/389,950, filed Feb. 20, 2009, entitled “Synchronized Telemetry From A Rotating Element,” hereby incorporated by reference in its entirety. In addition, the drilling system 1 can include a mud pulse telemetry system. For instance, a mud pulser 5 can be incorporated into the bottomhole assembly 6. The mud pulse telemetry system encodes data from downhole equipment, such as vibration information from the vibration analysis system 46 and, using the pulser 5, transmits the coded pulses to the surface 11. Further, drilling data can be transmitted to the surface using other means such as acoustic or electromagnetic transmission.
Referring to
In various embodiments, the input/output portion 106 includes a receiver of the computing device 100, a transmitter of the computing device 100, or an electronic connector for wired connection, or a combination thereof. The input/output portion 106 is capable of receiving and/or providing information pertaining to communication with a network such as, for example, the Internet. As should be appreciated, transmit and receive functionality may also be provided by one or more devices external to the computing device 100. For instance, the input/output portion 106 can be in electronic communication with the drilling data acquisition system 12 and/or one or more sensors disposed on the bottomhole assembly 6 downhole.
Depending upon the exact configuration and type of processor, the memory portion 104 can be volatile (such as some types of RAM), non-volatile (such as ROM, flash memory, etc.), or a combination thereof. The computing device 100 can include additional storage (e.g., removable storage and/or non-removable storage) including, but not limited to, tape, flash memory, smart cards, CD-ROM, digital versatile discs (DVD) or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, universal serial bus (USB) compatible memory, or any other medium which can be used to store information and which can be accessed by the computing device 100.
The computing device 100 also can contain the user interface portion 108, which can include an input device 110 and/or display 112 (input device 110 and display 112 not shown), that allows a user to communicate with the computing device 100. The user interface 108 can include inputs that provide the ability to control the computing device 100, via, for example, buttons, soft keys, a mouse, voice actuated controls, a touch screen, movement of the computing device 100, visual cues (e.g., moving a hand in front of a camera on the computing device 100), or the like. The user interface 108 can provide outputs, via a graphical user interface, including visual information, such as the visual indication of the plurality of operating ranges for one or more drilling parameters via the display 112. Other outputs can include audio information (e.g., via speaker), mechanically (e.g., via a vibrating mechanism), or a combination thereof. In various configurations, the user interface 108 can include a display, a touch screen, a keyboard, a mouse, an accelerometer, a motion detector, a speaker, a microphone, a camera, or any combination thereof. The user interface 108 can further include any suitable device for inputting biometric information, such as, for example, fingerprint information, retinal information, voice information, and/or facial characteristic information, for instance, so as to require specific biometric information for access the computing device 100.
Referring to
The computing device 100 depicted in
Referring to
In block 220, the software application can determine via a processor a first plurality of operating ranges for one or more drilling parameters. The first plurality of operating ranges can be based on a first duration, or moment, of time operating the drill string 4 during the drilling operation. The determination of the first plurality of operating ranges can be based on drilling information obtained in step 210, as well as the actual and measured drilling information obtained during a drilling operation.
The one or more drilling parameters can also include a first, or control set of drilling parameters that are typically controllable by the rig operator. The control set of drilling parameters are used to assist in controlling the drilling operation and can be the drilling parameters that can be optimized. Optimization is discussed below. The control set of drilling parameters include, but are not limited to, rate of penetration (ROP), weight-on-bit (WOB), mud flow rate, drill bit rotational speed and differential pressure. In addition, the drilling parameters can include a second, or process dependent, set of drilling parameters, the values of which are the result of the drilling operation. The process dependent set of drilling parameters can include torque (kft-lb), rotary speed (RPM), motor speed (RPM), mechanical specific energy (ksi), MSE scatter (ksi), slope of the mechanical specific energy (ksi), pressure (ksi), whirl, bit-bounce, and stick-slip. It should be appreciated that any system of units can be used during the display of the drilling parameters. The process dependent drilling parameters are measured or calculated values and are not necessarily optimizable, as noted above. The software application is configured to distinguish between control drilling parameters and process dependent drilling parameters and to display the applicable operating ranges accordingly. For instance, the control set of drilling parameters can include optimal operating ranges as well as a preferred operating range. Each drilling parameter, including the control set and process dependent drilling parameters, can be measured, calculated and/or predicted according to the methods and systems described in U.S. Pat. No. 8,453,764, entitled SYSTEM AND METHOD FOR MONITORING AND CONTROLLING UNDERGROUND DRILLING (the '764 patent), the entirety of which is herein incorporated by reference. In addition, in an embodiment of the present disclosure, the present disclosure can also include accessing and using data indicative of a pre-defined model of the drill string and desired drilling parameters, for instance as described in the '764 patent.
Returning to block 220, the software application can define the endpoints for each operating range (see endpoints 460, 462 . . . 474 in
The plurality of operating ranges determined in block 220 can include 1) at least one preferred operating range for each drilling parameter, and 2) at least one less preferred operating range for each drilling parameter. The preferred operating ranges can have more than one (a plurality) of preferred operating ranges. For instance, the preferred operating range can include an optimized operating range and a normal operating range. The less preferred operating ranges can have more than one (a plurality) of less preferred operating ranges. The less preferred operating range can include at least one of a high operating range, a severe operating range, and a critical operating range. Accordingly, the plurality of operating ranges can be referred to as a first, second, third . . . etc., operating range. For instance, a first operating range refers to the optimized operating range, the second operating range refers to the normal operating range, the third operating range refers to the high operating range, the fourth operating range refers to the severe operating range, and the fifth operating range refers to the critical operating range. Each drilling parameter can include one or more of the aforementioned operating ranges. In some instances, certain drilling parameters may include the optimized operating range as further detailed below.
The optimized operating range 420 (
Continuing with
In an accordance with the exemplary embodiment for an optimization drilling operation, set point values 415 (
The software application can determine endpoints based on the maximum value for ROP that yields the lowest expected wear on drill string components, taking into account the vibration data obtained during the drilling optimization operation, using the systems and methods disclosed in U.S. Pat. No. 8,453,764 noted above. In addition, the software application can also allow the user to input information for endpoint optimization determination. For instance, the user can limit the specific data used to conduct the optimization analysis. The graphical user interface is configured to cause the display of log plots for the data obtained measured over time. The user can then select a range of time over the optimization drilling operation that is used to perform the optimization analysis. It should be appreciated that other methods can be used to determine the optimal operation range for drilling parameter so long as the optimal operation takes into account drilling information that includes vibration information and expected drill string component useful life. In other words, the optimal operation ranges can be calculated as discussed above, or can be based on information concerning the drilling string components and predicted vibration information.
The normal operating range 430 (
Due to the complex nature of the drilling environment, such as pressure, axial, lateral and torsional vibrations of drill string, earthen formation characteristics, and the drill string design and characteristics, the relationship between desired drilling performance and the values for a specific drilling parameter may not be linear for each drilling parameter. In other words, there can be normal, high, severe, and critical operating ranges for each drilling parameter that are independent of a linear increase in the scale of a given drilling parameter. It has been found that certain drilling parameters may have normal and optimized operating ranges that are bounded, or fall between, less preferred operating ranges (see for instance
Referring again to
In block 240, the software application can receive data indicative of the actual operating value of the drilling parameter. For instance, as noted above, one or more of the sensors can obtain data that is indicative of the operating values of drill string components during the drilling operation. While in some instances sensors may measure a physical response of the drill string to the drilling operation, e.g., instantaneous rotational speed, processors disposed in the bottomhole assembly 6 can calculate the drilling parameter for the measured physical response. The actual operating value for a drilling parameter can be transmitted to the computing device 100 at the surface 11 and stored in the memory portion 104 of the computing device 100 for access by the software application. Alternatively or in addition, the physical response data can be transmitted to the computing device 100 at the surface and the actual operating value for the desired drilling parameter can be calculated at the surface. Further, the software application can receive the physical response of the drill string and calculate the actual operating value for the drilling parameter. Data indicative of the actual operating parameter can be transmitted to the surface computing devices via the communications systems discussed above.
In block 250, in response to receiving data indicative of the actual operating value for the drilling operation, or drill run, the software application can cause the display of the actual operating value for each of the drilling parameters relative to the first plurality of operating ranges. The software application may access or receive actual operating data, via the communications system discussed above, prior to the display of such data. The methods described here can also cause the actual operating value of each drilling parameter to be continuously updated as the drilling operation continues.
In block 260, the method can include a step of determining, via the computer processor, a second, updated plurality of operating ranges for the one or more drilling parameters. As further detailed below, the second, updated plurality of operating ranges may be based on a second moment or duration of time operating the drill string. The second, updated plurality of operating ranges includes at least the preferred operating range for each of the one or more drilling parameters and the less preferred operating range for each of the one or more drilling parameters.
In block 270, the software application can cause the user interface to display the second, updated plurality of operating ranges for the one or more drilling parameters. The user interface can display the second, updated plurality of operating ranges in response to the step of determining the second, updated plurality of operating ranges in block 260.
It should be appreciated that the steps illustrated in blocks 210-260 can be repeated any number of times during a drilling operation. For instance, the method can include the step of determining a third, updated plurality of operating ranges for the one or more drilling parameters. The third, updated plurality of operating ranges can be based on a third duration of time operating the drill string that is subsequent to the first and second durations of time. In response to the step of determining the third, updated plurality of operating ranges, the software application can display, via the user interface, the third, updated plurality of operating ranges for the one or more drilling operation parameters. Further, the method can be run continuously for a single drill run in a drilling operation, or for multiple drilling runs during a drilling operation. In addition, it should be appreciated that the determination of the third plurality of operating ranges, and the associated optimized range for the drilling parameters, can be associated with a respective first and second operating ranges for the drilling operation.
The computing device 100, and in particular the graphical user interface, can cause one or more authentication displays (not shown) to be presented to the user. Upon successful authentication, for instance, entry of appropriate user identifiers and passwords, the user interface can generate display 300 as shown
Further, the display 300 includes features that allow prior drilling operation information to be automatically populated into the data entry fields. For instance, the display 300 can include a “Bit Run” field 318 that can include a listing of each particular drill run or bit run performed by a drilling operation. If a user selects a previous bit run, by selecting “Bit Run #1”, for example, the software application causes the user interface to populate the various data entry fields with drilling data from the selected bit run. The user can input “cancel” at field 316 and the data fields will be depopulated. Alternatively, the user can enter drilling information and create a new “bit run”.
The user can input the various desired parameters for each drilling parameter in the data fields for each drilling component array 302, 304, 306, 308, 310 and 312. For instance, as shown in
Turning to
Turning to
The display 400 can include a digital dial for each drilling parameter. For instance, the display 400 includes a dial 410 that visually depicts the operating information for the weight on bit (WOB) (k-lb) of a drilling operation. While the display 400 illustrated in
The data band 412 includes the visual indication of the operating information for drilling parameters. In the illustrated embodiment in
Continuing with
As noted the above, the display 400 can also include dials for each process dependent drilling parameter. Dial 902 visually depicts the operating information for the torque (kft-lb) applied to drill string 4 in a drilling operation. Dial 904 visually depicts the operating information for the rotary rotational speed (RMP). Dial 906 visually depicts the operating information for the motor speed (RMP) of a drilling operation. Motor speed in this instance is a measured value that can fall within particular operating range (preferred or less preferred for example) and is process dependent. Dial 908 visually depicts the operating information for the mechanical specific energy (ksi) of a drilling operation. Dial 910 visually depicts the operating information for the measure of scatter or variability of mechanical specific energy (ksi) during a drilling operation. Dial 912 visually depicts the operating information for the slope of the mechanical specific energy (ksi) of a drilling operation. Dial 914 visually depicts the operating information for the standpipe pressure (ksi). Dials 916, 918 and 920 visually depict various parameters associated with drill string vibration. For instance, dial 916 visually depicts the operating information for the whirl of the drill string 4 during a drilling operation. Whirl in this instance is associated with lateral vibration of the drill sting 4 and can be determined via the vibration analysis system 46 as described above. Dial 918 visually depicts the operating information for the measured bit bounce of the drill bit 8 of drilling operation. Bit-bounce in this instance is associated with axial vibration of the drill sting 4 and can be determined via the vibration analysis system 46 as described above. Dial 920 visually depicts the operating information for stick-slip behavior of the drill string 4 for a drilling operation. Stick-Slip in this instance is associated with torsional vibration of the drill string 4 and can be determined via the vibration analysis system 46 as described above.
Turning to
The difference between operating in the optimized range 420 and the normal operating range 430 is dependent on the drilling operation and the pre-defined drilling plan. When a drilling parameter is operating in the optimized range 420, one or more additional parameters may fall within a normal operating range 430, for instance, bit whirl is minimized and MSE scatter is low, indicating that the drill string is operating consistent with a pre-defined drill plan. Operation within high or yellow operating range 440 would indicate that the drilling parameters exceed the normal operation range. For instance, the actual ROP in dial 510 may fall within preferred, or green, operating range 430 and the WOB shown in dial 410 and stick-slip shown in dial 920 are illustrated as operating in the high ranges 440 (yellow in each dial 510 and 920). Yet, the drill bit RPM may be shown in dial 710 as operating within the optimal preferred range 420, shown in blue. Operating ROP in the preferred range 420 may be acceptable to the user 24 viewing the display 400, and no specific adjustment in the drilling process controls will be initiated. By providing a visual indication of one or operating ranges for one or more drilling parameters, a user 24 can observe the impact of adjusting drilling parameters on the drilling operation.
As noted above, each drilling parameter can have more than one (for instance a plurality) of operating ranges for each level or operation ranges, e.g. normal, high, severe, and critical. The relationship among each level of operating range may not be linear. For instance, an increase (or decrease) in a value for a drilling parameter does not necessarily mean that the escalation of the operating ranges from normal to critical will be sequential. Referring to
The computing device 100 can cause the user interface to display each operating range on the digital dial band 412 to account for multiple operating ranges and their relationship along a particular scale of the drilling parameter. As discussed above, the computing device 100, via processing portion 102, can determine the operating range end points for each specific operating range and cause the user interface to display the respective operating ranges in a respective color along the data band of the dial in the display 400. Range endpoints can be defined as the operating value where two operating ranges are adjacent, for instance at WOB equal to 5 (k-lb) (
Referring to
Turning now to
Referring to
Referring to
Referring to
Referring to
Referring to
While example embodiments of devices for executing the disclosed techniques are described herein, the underlying concepts can be applied to any computing device, processor, or system capable of communicating and presenting information as described herein. The various techniques described herein can be implemented in connection with hardware or software or, where appropriate, with a combination of both. Thus, the methods and apparatuses described herein can be implemented, or certain aspects or portions thereof, can take the form of program code (i.e., instructions) embodied in tangible storage media, such as floppy diskettes, CD-ROMs, hard drives, or any other machine-readable storage medium (computer-readable storage medium), wherein, when the program code is loaded into and executed by a machine, such as a computer, the machine becomes an apparatus for performing the techniques described herein. In the case of program code execution on programmable computers, the computing device will generally include a processor, a storage medium readable by the processor (including volatile and non-volatile memory and/or storage elements), at least one input device, and at least one output device as described above. The program(s) can be implemented in assembly or machine language, if desired. The language can be a compiled or interpreted language, and combined with hardware implementations.
The techniques described herein also can be practiced via communications embodied in the form of program code that is transmitted over some transmission medium, such as over electrical wiring or cabling, through fiber optics, or via any other form of transmission, for instance such as mud telemetry and other data transfers methods for drilling operations described above. When implemented on a general-purpose processor, the program code combines with the processor to provide a unique apparatus that operates to invoke the functionality described herein. Additionally, any storage techniques used in connection with the techniques described herein can invariably be a combination of hardware and software.
While the techniques described herein can be implemented and have been described in connection with the various embodiments of the various figures, it is to be understood that other similar embodiments can be used or modifications and additions can be made to the described embodiments without deviating therefrom. For example, it should be appreciated that the steps disclosed above can be performed in the order set forth above, or in any other order as desired. Further, one skilled in the art will recognize that the techniques described in the present application may apply to any environment, whether wired or wireless, and may be applied to any number of such devices connected via a communications network and interacting across the network. Therefore, the techniques described herein should not be limited to any single embodiment, but rather should be construed in breadth and scope in accordance with the appended claims.
This application is a continuation of U.S. Design Application No. 29/460,812, filed Jul. 15, 2013, the entire contents of which are incorporated by reference in this application for all purposes.
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| Number | Date | Country | |
|---|---|---|---|
| 20150014058 A1 | Jan 2015 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 29460812 | Jul 2013 | US |
| Child | 14026332 | US |
