Patent Grant
12258855
Embodiments of the disclosure are directed to mud pulse telemetry in drilling operations. More particularly, embodiments of the disclosure are directed to data compression techniques for downhole telemetry in drilling/logging operations.
During drilling operations for the extraction of hydrocarbons, a variety of recording and transmission techniques may be used to measure or record real-time data from the vicinity of a drill bit. These measurements of the surrounding subterranean formations may be made using downhole measurement and logging tools, such as directional drilling tools, measurement-while-drilling (MWD) tools, and/or logging-while-drilling (LWD) tools, which help characterize the formations and aid in making operational decisions.
The downhole measurement and logging tools obtain image data and transmit to a surface using mud pulse telemetry techniques. Communication between the downhole tools and a processor at the surface (or from the surface to downhole tools) may often employ compression methods to compress data transmitted between these devices. In some existing compression methods, the raw image data (corresponding to raw sensor data) may be collected at a predetermined reference point and the downhole tool may transmit delta values between the raw image data and actual sensor data to the surface. These compression methods may work best for small delta values. However, these compression methods may not be beneficial for large delta values.
Furthermore, some existing compression methods may cause a delay in data transmission. Information/data about the geographical properties of the formation surrounding the wellbore gathered downhole may be needed at the surface as soon as any change in the information is acquired. A limiting factor in sending data from the downhole devices to the surface is the speed at which the information may be transmitted within the mud column. The current physical data rate of typical telemetry tools may range from 2-20 bits per second (bps). This limited bandwidth may constrain the volume of real-time data being transmitted to the surface operations to effectively control the drilling tools and build a dense geological model. Thus, a mechanism to optimize the data being transmitted to the surface may be useful for formation evaluation and/or controlling the drilling/logging operations.
For a more complete understanding of this disclosure, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description, wherein like reference numerals represent like parts.
In the following detailed description of the illustrative embodiments, reference is made to the accompanying drawings that form a part hereof. These embodiments are described in sufficient detail to enable those skilled in the art to practice the invention, and it is understood that other embodiments may be utilized and that logical structural, mechanical, electrical, and chemical changes may be made without departing from the spirit or scope of the invention. To avoid detail not necessary to enable those skilled in the art to practice the embodiments described herein, the description may omit certain information known to those skilled in the art. The following detailed description is, therefore, not to be taken in a limiting sense, and the scope of the illustrative embodiments is defined only by the appended claims.
Illustrative embodiments and related methodologies of the present disclosure will be described below in reference to
In conventional compression methods, delta values between the image data (corresponding to raw sensor data) collected at the predetermined reference point and actual sensor data may be transmitted to the surface of the wellbore. However, these compression methods may not be beneficial for large delta values and may also cause a delay in data transmission.
As will be described in further detail below, embodiments of the present disclosure may be used to efficiently compress the data and significantly improve the effective data rate of the downhole telemetry according to an image imposition scheme. The image imposition scheme may be used to minimize the number of bits being transmitted to a surface device and to optimize the telemetry data rate. In some embodiments, the disclosed methods may be applied to transmit a downhole image along with the delta values. As these methods minimize the delta values, it may be possible to increase the quality of the image to be transmitted.
Because of the speed at which downhole tools traverse the formations in MWD and LWD systems, well trajectory data such as inclination and azimuth changes may not rapidly change between readings taken by the downhole tools. Based on this fact, and possibly to reduce transmission error propagation and to increase an effective data transmission rate in a mud pulse telemetry system, various embodiments of the present disclosure may use data compression systems and methods that can optimize the bit allocation for transmitting the compressed data uphole with a higher effective transmission rate. For example, instead of transmitting the full data values (e.g., uncompressed data) every time, delta values between previously transmitted data and the information of the current data may be sent. Thus, by compressing the data prior to its transmission, it may be possible to reduce the overall number of bits of information which need to be sent to the surface relative to the same amount of uncompressed data, thus increasing the effective data rate and reducing the data rate demand on telemetry hardware.
In some embodiments, the disclosed methods may be used to group the real-time data that provide similar measurements to minimize the bits required for data transmission. Furthermore, grouping the data that measures the same or similar formation properties may also benefit multi-spacing/frequency resistivity measurements.
The disclosed methods and systems may be applied to any formation property measurements, downhole imaging, or any other measurements having a series of data. The rate of compression may increase as more data gets compressed as of initial transmission of shape and location of the reference shape.
The disclosed methods and systems may Increase the effective data rate, reduce the data rate demand on telemetry hardware, or a combination of both. The mud-pulse telemetry system depends on the number of pulse actuation cycles. By reducing the number of cycles, the repair and maintenance service interval may be extended while improving the system reliability.
Additional features and advantages of the disclosed embodiments will be or will become apparent to one of ordinary skill in the art upon examination of the following figures and detailed description. It is intended that all such additional features and advantages be included within the scope of the disclosed embodiments. Further, the illustrated figures are only exemplary and are not intended to assert or Imply any limitation with regard to the environment, architecture, design, or process in which different embodiments may be implemented.
In the present application, the downhole tool 136 may be capable of measuring properties of the subterranean formation 118 proximal to the wellbore 116. The downhole tool 136 may transmit the measured data wired or wirelessly to a processor 138 at the surface. Transmission of the data is illustrated at link 140 to demonstrate communicable coupling between the processor 138 and the downhole tool 136 and does not necessarily indicate the path to which communication is achieved. In one or more implementations, the processor 138 may be, or may be a part of, a downhole processor located downhole to carry out encoder operations for transmitting the measured data uphole to the surface.
The downhole tool 136 may include one or more of an angle sensor, an azimuthal deep resistivity sensor, an azimuthal focused resistivity sensor, an azimuthal lithodensity sensor, an at-bit inclination sensor, or an at-bit azimuthal gamma ray sensor. For example, the azithumal lithodensity sensor may combine density and photoelectric (Pe) measurements with azimuthal binning of data and an independent acoustic standoff sensor (not shown) for petrophysical evaluation of the subterranean formation 118 (e.g., a reservoir). The downhole tool 136 with the azimuthal lithodensity sensor can obtain measurements relating to formation dip and borehole shape information for geosteering and hole quality applications. In one or more implementations, the downhole tool 136 is constructed with azimuthally responsive sensors distributed azimuthally around a symmetry axis of the downhole tool 136 that make it possible to make measurements of the azimuthal distribution of formation properties without rotating the drill string 108 or sensor package. In one or more implementations, the downhole tool 136 is constructed with an angle sensor to determine sensor data based on measurements obtained from the angle sensor.
A pump 120 (e.g., a mud pump) circulates drilling fluid 122 through a feed pipe 124 and to the kelly 110, which conveys the drilling fluid 122 downhole through the interior of the drill string 108 and through one or more orifices in the drill bit 114. The drilling fluid 122 is then circulated back to the surface via an annulus 126 defined between the drill string 108 and the walls of the wellbore 116. At the surface, the recirculated or spent drilling fluid 122 exits the annulus 126 and may be conveyed to one or more fluid processing unit(s) 128 via an interconnecting flow line 130. After passing through the fluid processing unit(s) 128, a “cleaned” drilling fluid 122 is deposited into a nearby retention pit 132 (e.g., a mud pit). While illustrated as being arranged at the outlet of the wellbore 116 via the annulus 126, those skilled in the art will readily appreciate that the fluid processing unit(s) 128 may be arranged at any other location in the drilling assembly 100 to facilitate its proper function, without departing from the scope of the disclosure.
In one or more implementations, pressure transducers are mounted in one or more locations along the feed pipe 124. The transducers include signal conditioning electronics that may be used to send electrical signals corresponding to pressure impulses to a surface receiver. The surface receiver may consist of an analog front end that is interfaced to the processor 138. In one or more implementations, the processor 138 may be, or may be a part of, the surface receiver. For mud pulse telemetry, the processor 138 may be interfaced to a telemetry channel, which has a relatively low data rate compared to the demand necessary for successful transmission of images in real-time. The telemetry channel may be an electromagnetic telemetry channel or an acoustic telemetry channel.
The processor 138 may include a portion of computer hardware used to implement the various illustrative blocks, modules, elements, components, methods, and algorithms for analyzing the measurements described herein. The processor 138 may be configured to execute one or more sequences of instructions, programming stances, or code stored on a non-transitory, computer-readable medium. The processor 138 can be, for example, a general purpose microprocessor, a microcontroller, a digital signal processor, an application specific integrated circuit, a field programmable gate array, a programmable logic device, a controller, a state machine, a gated logic, discrete hardware components, an artificial neural network, or any like suitable entity that can perform calculations or other manipulations of data. In some embodiments, computer hardware can further include elements such as, for example, a memory (e.g., random access memory (RAM), flash memory, read only memory (ROM), programmable read only memory (PROM), erasable read only memory (EPROM)), registers, hard disks, removable disks, CD-ROMS, DVDs, or any other like suitable storage device or medium. The memory may store a library of pre-determined shapes (described in more detail below) and, in embodiments implementing processing functionality at least in part with software, instructions to be executed by the processor(s) 138. In some embodiments, the memory may further store raw/initial sensor image data as well as processed sensor image data.
Executable sequences described herein can be implemented with one or more sequences of code contained in a memory. In some embodiments, such code can be read into the memory from another machine-readable medium. Execution of the sequences of instructions contained in the memory can cause a processor 138 to perform the process steps to analyze the measurements described herein. One or more processors 138 in a multi-processing arrangement can also be employed to execute instruction sequences in the memory. In addition, hard-wired circuitry can be used in place of or in combination with software instructions to implement various embodiments described herein. Thus, the present embodiments are not limited to any specific combination of hardware and/or software.
As used herein, a machine-readable medium will refer to any medium that directly or indirectly provides instructions to the processor 138 for execution. A machine-readable medium can take on many forms including, for example, non-volatile media, volatile media, and transmission media. Non-volatile media can include, for example, optical and magnetic disks. Volatile media can include, for example, dynamic memory. Transmission media can include, for example, coaxial cables, wire, fiber optics, and wires that form a bus. Common forms of machine-readable media can include, for example, floppy disks, flexible disks, hard disks, magnetic tapes, other like magnetic media, CD-ROMs, DVDs, other like optical media, punch cards, paper tapes and like physical media with patterned holes, RAM, ROM, PROM, EPROM and flash EPROM.
In one or more implementations, as shown in
To facilitate such comparisons, the characteristics of the reference shape 302 or any other shape may be selected/modified by various methods. In some embodiments, the pre-determined reference shape 302 may be selected from a plurality of pre-determined shapes stored in the library. The library may have the plurality of the pre-determined shapes that differ from each other in the values of one or more parameters of the formation. The downhole tool 136 may evaluate and determine which of the pre-determined shapes to be used that can be closely imposed on the first shape 206 on the plot 300A. In some embodiments, the downhole tool 136 may be programmed to transmit the predetermined reference shape, or a code and/or a size of the pre-determined reference shape to the processor 138 at the surface. In some embodiments, the downhole tool 136 may be programmed to transmit a phase and a magnitude of a sine wave function to the processor 138 at the surface to determine a reference shape (e.g., a circle/oval) to be closely imposed on the first shape 206. In some examples, the information may be formatted into binary data for transmission uphole. The processor 138 may then decode the information from downhole to obtain the series of the data.
As can be observed from PG. 3A, an area difference between the pre-determined reference shape 302 and the first shape 206 in
In some embodiments, the pre-determined reference shape 302 may be optimized by reducing the resolution of the location information. As discussed above, the downhole telemetry may have limited bandwidth. Increasing the resolution of the location of the pre-determined reference shape 302 may increase the burden on downhole telemetry. Thus, instead of determining accurate locations, the location of the pre-determined reference shape 302 may be determined “roughly close” to the first shape 206 to reduce the bandwidth requirements to transmit the shape location information e.g., a direction and magnitude) to the surface.
In some examples, the pre-determined reference shape may be selected from 32 images stored in the library, 16 different directions, and 8 different values for magnitude. In one example, the downhole tool 136 may require a maximum of 56 bits to transmit the image for imposition. The disclosed methods may be applied to any formation property measurements, downhole imaging, or any other measurements that have a series of data. The rate of compression increases as more data gets compressed since the initial transmission of shape and its location becomes an investment.
Consider for purposes of explanation, and with reference to Table 1 below, a comparison of number of bits required to transmit by the downhole tool 136 to the processor 138 at the surface by the conventional compression method and the disclosed image imposition method may be illustrated. Table 1 shows the effectiveness of the disclosed image imposition method in reducing the number of bits required to transmit the sensor data from the downhole to the surface of the wellbore, and increasing the effective data throughput. As exemplified in Table 1, column 2 may represent the numeric values received from raw sensor data. The raw sensor data may be collected as the downhole tool 136 rotates within the borehole and binned into a plurality of azimuthal bins according to the azimuthal direction in which the downhole tool 136 was positioned when the raw sensor data was acquired. For example, sixteen bins from 0-15 in column 1 are shown in Table 1. However, in general, any number of bins may be used. In the conventional delta compression method, the delta values (e.g. in column 3) may be determined by calculating a difference between the reference shape 202 and the first shape 206 as shown in
At step 402, the method 400 may comprise obtaining, by the downhole tool 136, the first shape 206 of sensor data representing one or more characteristics of a wellbore. In one embodiment, the sensor data may be raw sensor data determined based on measurements obtained from an angle sensor incorporated within the downhole tool 136.
At step 404, the method 400 may comprise comparing, by the downhole tool 136, the first shape among a set of pre-determined reference shapes stored in a downhole memory so as to select a pre-determined reference shape that can be imposed on the first shape 206. The pre-determined reference shape 302 may comprise any form of shapes including a circle, an oval, a rectangle, or an eclipse. In one embodiment, the method may further comprise selecting the pre-determined reference shape that closely matches the first shape 206 and/or that minimizes an area between the first shape 206 and the pre-determined reference shape 302.
At step 406, the method 400 may comprise calculating one or more delta values between the first shape 206 and the selected pre-determined reference shape 302.
At step 408, the method may comprise transmitting the pre-determined reference shape 302 and the delta values to the processor 138 at a surface of the wellbore 116. In one embodiment, the method may further comprise transmitting the pre-determined reference shape 302, size and/or a code of the pre-determined reference shape 302, or a location of the pre-determined reference shape 302 to the processor 138 in real-time during a drilling operation or a logging operation.
In some further embodiments of this disclosure, a delta value compression system and method may be utilized to group the data that measures similar formation properties to reduce the data bandwidth requirements. In general, a well trajectory data such as inclination data and azimuth data may change very little between subsequent samples. Hence, instead of transmitting the full values every time, transmitting a full value from one measurement and transmit a delta value from the other measurement, may be a more effective way of reducing the number of bits to be transmitted and improving the data rate/bandwidth. Furthermore, in following datasets, transmitting a delta value based on a difference between previously transmitted data and current data may further reduce the bandwidth requirements. Thus, grouping the data that measures similar formation properties may reduce the data bandwidth requirements.
To implement this, the downhole tool 136 may receive downhole measurements from a plurality of downhole sensors that measure similar formation properties during a downhole drilling operation in the wellbore 116, wherein the sensors are disposed on the drill string 108 at different locations. The plurality of sensors may comprise at-bit inclination sensor, a survey senor, a pressure sensor, a directional sensor, and/or a resistivity sensor. In some embodiments, the downhole tool 136 may receive a first measurement from a first downhole sensor and a second measurement from a second downhole sensor of the plurality of downhole sensors. The downhole tool 136 may calculate a first delta value between the first measurement and the second measurement, and may transmit the first measurement and the first delta value to the processor 138 at the surface of the wellbore 116. In some embodiments, the downhole tool 136 may receive a third measurement from the first downhole sensor, calculate a second delta value between the third measurement and the transmitted first measurement, and transmit the first delta value and the second delta value to the processor 138. In this way, grouping the data that measures similar formation properties may reduce the data bandwidth requirements.
Consider for purposes of explanation, two exemplary types of telemetry data A and B may be referred as shown in Table 2 below.
As exemplified in Table 2, data type A (e.g., column 1) may be the measurements received from the survey sensor and data type B (e.g., column 2) may be measurements received from the at-bit inclination sensor. Both data types A and B may measure similar formation properties of the formation. As exemplified in Table 2, the data values of the survey sensor and at-bit inclination sensor are different, however, a delta value (e.g., value in column 3) which is a difference between two data values (column 3) is much less than the magnitude of the data values. In some cases, data type A has experienced no change in value from the value from data type B, then the preferred embodiments only a data value of zero may be sent. Likewise, if parameter A experiences only a small change in value from the value of parameter B, a number representing the change in value may be transmitted to the surface. This change in value, or delta value, may require fewer bits therefore, the overall number of bits to transfer the information is reduced, increasing the effective data throughput. Furthermore, in some embodiments, the data transmitted onwards may be the delta from the initial value. In some cases, the data may be re-calibrated after a certain number of data transmissions.
At step 602, the method 600 may comprise receiving measurements from a plurality of downhole sensors measuring similar formation properties during a downhole drilling operation in a wellbore, wherein the sensors are disposed on the drill string 108 at different locations. In one embodiment, the sensors are configured to collect information regarding the formation around a borehole and/or trajectory of the wellbore 116.
At step 604, the method 600 may comprises receiving a first measurement from a first downhole sensor of the plurality of downhole sensors.
At step 606, the method 600 may comprises receiving a second measurement from a second downhole sensor of the plurality of downhole sensors.
At step 608, the method 600 may comprise calculating, by the downhole tool 136, a first delta value between the first measurement and the second measurement.
At step 610, the method may comprise transmitting the first measurement and the first delta value to the processor 138 at the surface of the wellbore 116. In one embodiment, the method may further comprise receiving a third measurement from the first downhole sensor, calculating a second delta value between the third measurement and the transmitted first measurement, and transmitting the first delta value and the second delta value to the processor 138.
The bus 708 collectively represents all system, peripheral, and chipset buses that communicatively connect the numerous internal devices of the electronic system 700. In one or more implementations, the bus 708 may comprise a mud system through which the surface and downhole processing units communicate. In one or more implementations, the bus 708 communicatively connects the one or more processor(s) 712 with the ROM 710, the system memory 704, and the permanent storage device 702. From these various memory units, the one or more processor(s) 712 retrieve instructions to execute and data to process in order to execute the processes of the present disclosure. The one or more processor(s) 712 can be a single processor or a multi-core processor in different implementations.
The ROM 710 stores static data and instructions that are needed by the one or more processor(s) 712 and other modules of the electronic system 700. The permanent storage device 702, on the other hand, may be a read-and-write memory device. The permanent storage device 702 may be a non-volatile memory unit that stores instructions and data even when the electronic system 700 is off. In one or more implementations, a mass-storage device (such as a magnetic or optical disk and its corresponding disk drive) may be used as the permanent storage device 702.
In one or more implementations, a removable storage device (such as a floppy disk, flash drive, and its corresponding disk drive) may be used as the permanent storage device 702. Like the permanent storage device 702, the system memory 704 may be a read-and-write memory device. However, unlike the permanent storage device 702, the system memory 704 may be a volatile read-and-write memory, such as random access memory. The system memory 704 may store any of the instructions and data that one or more processor(s) 712 may need at runtime. In one or more implementations, the processes of the present disclosure are stored in the system memory 704, the permanent storage device 702, and/or the ROM 710. Fro these various memory units, the one or more processor(s) 712 retrieve instructions to execute and data to process in order to execute the processes of one or more implementations.
The bus 708 also connects to the input device interface 714 and the output device interface 706. The input device interface 714 enables a user to communicate information and select commands to the electronic system 700. Input devices that may be used with the input device interface 714 may include, for example, alphanumeric keyboards and pointing devices. The output device interface 706 may enable, for example, the display of images generated by the electronic system 700. Output devices that may be used with the output device interface 706 may include, for example, printers and display devices, such as a liquid crystal display (LCD), a light emitting diode (LED) display, an organic light emitting diode (OLEIC) display, a flexible display, a flat panel display, a solid state display, a projector, or any other device for outputting information. One or more implementations may include devices that function as both input and output devices, such as a touchscreen. In these implementations, feedback provided to the user can be any form of sensory feedback, such as visual feedback, auditory feedback, or tactile feedback; and input from the user can be received in any form, including acoustic, speech, or tactile input.
The bus 708 also may couple the electronic system 700 to one or more networks (not shown) through one or more network interface(s) 716. One or more network interface(s) may include an Ethernet interface, a Wi-Fi interface, or generally any interface for connecting to a network. In this manner, the electronic system 700 can be a part of one or more networks of computers (such as a local area network (“LAN”), a wide area network (“WAN”), or an Intranet, or a network of networks, such as the Internet. Any or all components of the electronic system 600 can be used in conjunction with the present disclosure.
The electronic system 700 is suitable for collecting, processing and displaying logging data. In one or more implementations, a user can interact with the electronic system 700 via the input device interface 714 to send one or more commands to drilling assembly 100 to adjust its operation in response to received logging data. In one or more implementations, the downhole tool 136 is coupled to the processor 712 via the bus 708 to enable the electronic system 700 to communicate with the drill assembly 100 including the drill bit 114. In accordance with user input received via the input device interface 714 and program instructions from the system memory 704 and/or the ROM 710, the processor 712 processes the received telemetry information received via the network interface 716 over the bus 708. The processor 712 can construct formation property logs (including one or more borehole wall images), and display them to the user via the output device interface 706.
The following are non-limiting, specific embodiments in accordance with the present disclosure:
A first embodiment, which is a method, comprising obtaining, by a downhole processor, a first shape of sensor data representing one or more characteristics of a wellbore, comparing, by the downhole tool, the first shape with a set of pre-determined reference shapes stored in a downhole memory to select a pre-determined reference shape that can be imposed on the first shape, calculating one or more delta values between the first shape and the selected pre-determined reference shape, and transmitting the pre-determined reference shape and the delta values to a processor at a surface of the wellbore.
A second embodiment, which is the method of the first embodiment, further comprising selecting the pre-determined reference shape comprises selecting the pre-determined reference shape that minimizes an area between the first shape and the pre-determined reference shape.
A third embodiment, which is the method of any of the first and the second embodiments, further comprising selecting the pre-determined reference shape comprises selecting the pre-determined reference shape that closely matches the first shape.
A fourth embodiment, which is the method of any of the first through the third embodiments, further comprising transmitting a code and/or size of the pre-determined reference shape and the delta values to the processor via the downhole tool.
A fifth embodiment, which is the method of any of the first through the fourth embodiments, further comprising transmitting a magnitude and a phase of a sine-wave function and the delta values to the processor via the downhole tool.
A sixth embodiment, which is the method of any of the first through the fifth embodiments, further comprising transmitting a magnitude and/or a location of the pre-determined reference shape and the delta values to the processor via the downhole tool.
A seventh embodiment, which is the method of any of the first through the sixth embodiments, further comprising transmitting the pre-determined reference shape, size and/or a code of the pre-determined reference shape, or a location of the pre-determined reference shape to the processor in real-time during a drilling operation or a logging operation.
An eighth embodiment, which is the method of any of the first through the seventh embodiments, wherein the pre-determined reference shape may comprise a circle, an oval, a rectangle, or an ellipse.
A ninth embodiment, which is the method of any of the first through the eighth embodiments, further comprising determining the sensor data by the downhole tool at different points around a circumference of the wellbore drilled within a formation at a selected depth.
A tenth embodiment, which is the method of any of the first through the ninth embodiments, further comprising assigning the delta values to a plurality of azimuthal bins, wherein each azimuthal bin corresponding to an angular sector around the circumference of the wellbore.
An eleventh embodiment, which is the method of any of the first through the tenth embodiments, wherein the sensor data may be determined based on measurements obtained from an angle sensor incorporated within the downhole tool.
A twelfth embodiment, which is the method of any of the first through the eleventh embodiments, wherein the sensor data may comprise one or more of azimuthal density data, azimuthally focused resistivity data, azimuthally deep resistivity, azimuthal acoustic compressional and shear images, acoustic borehole caliper and reflectance, and spectral natural gamma ray and non-spectral natural gamma imaging.
A thirteenth embodiment, which is a system, comprising a downhole memory, a downhole tool coupled to the downhole memory and configured to obtain a first shape of sensor data representing one or more characteristics of a wellbore, compare the first shape with a set of pre-determined reference shapes stored in the downhole memory to select a pre-determined reference shape that can be imposed on the first shape, and calculate one or more delta values between the first shape and the selected pre-determined reference shape, and a transmitter to transmit the pre-determined reference shape and the delta values to a processor at a surface of the wellbore.
A fourteenth embodiment, which is the system of the thirteenth embodiment, further comprising a downhole sensor device configured to collect the sensor data while the downhole sensor device is within the wellbore.
A fifteenth embodiment, which is the system of any of the thirteenth through the fourteenth embodiments, wherein the downhole tool is further configured to select the pre-determined reference shape that minimizes an area between the first shape and the pre-determined reference shape.
A sixteenth embodiment, which is the system of any of the thirteenth through the fifteenth embodiments, wherein the downhole tool is further configured to select the pre-determined reference shape that closely matches the first shape.
A seventeenth embodiment, which is the system of any of the thirteenth through the sixteenth embodiments, wherein the transmitter is further configured to transmit a code and/or a size of the pre-determined reference shape and the delta values to the processor via the downhole tool.
An eighteenth embodiment, which is the system of any of the thirteenth through the seventeenth embodiments, wherein the transmitter is further configured to transmit a magnitude and a phase of a sine-wave function and the delta values to the processor via the downhole tool.
A nineteenth embodiment, which is the system of any of the thirteenth through the eighteenth embodiments, wherein the transmitter is further configured to transmit a magnitude and/or a location of the pre-determined reference shape and the delta values to the processor via the downhole tool.
A twentieth embodiment, which is the system of any of the thirteenth through the nineteenth embodiments, wherein the transmitter is further configured to transmit the pre-determined reference shape, a size and/or a code of the pre-determined reference shape, or a location of the pre-determined reference shape to the processor in real-time during a drilling operation or a logging operation.
A twenty-first embodiment, which is the system of any of the thirteenth through the twentieth embodiments, wherein the pre-determined reference shape comprises a circle, an oval, a rectangle, or an ellipse.
A twenty-second embodiment, which is the system of any of the thirteenth through the twenty-first embodiments, further comprising a downhole sensor configured to collect the sensor data at different points around a circumference of the wellbore drilled within a formation at a selected depth.
A twenty-third embodiment, which is the system of any of the thirteenth through the twenty-second embodiments, wherein the downhole tool is further configured to assign the delta values to a plurality of azimuthal bins, wherein each azimuthal bin corresponding to an angular sector around the circumference of the wellbore.
A twenty-fourth embodiment, which is the system of any of the thirteenth through the twenty-third embodiments, wherein the sensor data determined based on measurements obtained from an angle sensor incorporated within the downhole tool.
A twenty-fifth embodiment, which is the system of any of the thirteenth through the twenty-fourth embodiments, wherein the sensor data comprises one or more of azimuthal density data, azimuthally focused resistivity data, azimuthally deep resistivity, azimuthal acoustic compressional and shear images, acoustic borehole caliper and reflectance, and spectral natural gamma ray and non-spectral natural gamma imaging.
A twenty-sixth embodiment, which is a method, comprising receiving measurements from a plurality of downhole sensors measuring similar formation properties during a downhole drilling operation in a wellbore, wherein the sensors are disposed on a drill string at different locations, receiving a first measurement from a first downhole sensor of the plurality of downhole sensors, receiving a second measurement from a second downhole sensor of the plurality of downhole sensors, calculating, by a downhole tool, a first delta value between the first measurement and the second measurement, and transmitting the first measurement and the first delta value to a processor at a surface of the wellbore.
A twenty-seventh embodiment, which is the method of the twenty-sixth embodiment, further comprising receiving a third measurement from the first downhole sensor, calculating a second delta value between the third measurement and the transmitted first measurement, and transmitting the first delta value and the second delta value to the processor.
A twenty-eighth embodiment, which is the method any of the twenty-sixth and the twenty-seventh embodiments, wherein the sensors are configured to collect information regarding a formation around a borehole and/or trajectory of the wellbore.
A twenty-ninth embodiment, which is the method of any of the twenty-sixth through the twenty-eighth embodiments, wherein the sensors comprise at-bit inclination sensor, a survey sensor, a pressure sensor, a directional sensor, and/or a resistivity sensor.
A thirtieth embodiment, which is the method of any of the twenty-sixth through the twenty-ninth embodiments, wherein the formation properties comprise information regarding a formation around a borehole and/or trajectory of the wellbore.
A thirty-first embodiment, which is a method, comprising obtaining at least two resistivity measurements at different orientations of a resistivity logging tool deployed in a wellbore, calculating delta values between the at least two resistivity measurements, and transmitting at least one resistivity measurement and the delta values to a processor at a surface of the wellbore.
A thirty-second embodiment, which is the method of the thirty-first embodiment, wherein the at least two resistivity measurements are obtained by a plurality of spaced transmitters and receivers of the resistivity logging tool using multiple frequencies.
A thirty-third embodiment, which is a non-transitory computer readable medium, comprising a computer program product for use by a downhole tool, the computer program product comprising computer executable instructions stored on the non-transitory computer readable medium such that when executed by a processor cause the downhole tool to perform the disclosed method.
A thirty-fourth embodiment, which is a system, comprising a storage means including instructions, a processing means coupled to the storage means, the processing means configured to implement the instructions to cause a downhole hole to obtain a first shape of sensor data representing one or more characteristics of a wellbore, compare the first shape with a set of pre-determined reference shapes stored in the downhole memory to select a pre-determined reference shape that can be imposed on the first shape, and calculate one or more delta values between the first shape and the selected pre-determined reference shape, and a transmitting means coupled to the processing means, the transmitting means configured to transmit the pre-determined reference shape and the delta values to a processor at a surface of the wellbore.
While embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of this disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting, Many variations and modifications of the embodiments disclosed herein are possible and are within the scope of this disclosure. Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element may be present in some embodiments and not present in other embodiments. Both alternatives are intended to be within the scope of the claim, Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.
Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of this disclosure. Thus, the claims are a further description and are an addition to the embodiments of this disclosure. The discussion of a reference herein is not an admission that it is prior art, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein.
This application claims priority to U.S. Provisional Application No. 63/272,886 filed on Oct. 28, 2021. The disclosures of the aforementioned applications are hereby incorporated by reference in their entirety.
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| 63272886 | Oct 2021 | US |
