Patent Grant
10190408
The present disclosure relates to a drilling operation, and in particular to a system, apparatus, and method for monitoring a drilling operation.
Wells drilled for oil, gas and other purposes may be thousands of feet underground, change direction and extend horizontally. Communication systems have been developed that transmit information regarding the well path, formation properties, and drilling conditions measured with sensors at or near the drill bit. Obtaining and transmitting information is commonly referred to as measurement-while-drilling (MWD) and logging-while-drilling (LWD). One transmission technique is electromagnetic (EM) telemetry or telemetry. Telemetry systems include tools that are configured to transmit an electromagnetic signal to the surface having encoded therein directional, formation and other drilling data obtained during the drilling operation.
An embodiment of the present disclosure includes a method for monitoring a drilling operation of a drilling system. The drilling system has a drill string configured to form a borehole in an earthen formation during the drilling operation. The method includes the step of receiving a signal via a first pair of antennas positioned on a surface of the earthen formation, the signal being transmitted by a telemetry tool supported by the drill string and being located at a downhole end of the borehole during the drilling operation. The signal received by the first pair of antennas has a first signal characteristic. The method includes receiving the signal via a second pair of antennas positioned on the surface at a different location than that of the first pair of antennas. The signal received by the second pair of antennas has a second signal characteristic. Further, the method includes identifying which of the first signal characteristic and the second signal characteristic of the signal received by the respective first and second pairs of antennas is a preferred signal characteristic. The method can include decoding the signal received by one of the first and second pairs of antennas that has received the signal with the preferred signal characteristic.
In another embodiment of a method for monitoring a drilling operation, the method can include transmitting a signal from the telemetry tool at a first downhole location in the borehole during a first duration of the drilling operation. The method can further include receiving the signal via at least two antenna pairs. The at least two antenna pairs are positioned on the surface and spaced apart with respect to each other and the borehole. The method can include receiving, during the first duration of the drilling operation, a surface signal from each of the at least two antenna pairs that received the signal. Further, the method can include decoding the surface signal from one of the at least two antenna pairs that received the signal having a preferred signal characteristic.
Another embodiment of present disclosure includes a telemetry system for a drilling operation. The system includes a plurality of antenna pairs, each antenna pair configured to receive a signal that is transmitted by a telemetry tool at a downhole location in the borehole during the drilling operation. The system further includes a receiver assembly configured for electronic connection with each of the plurality of antenna pairs. The receiver assembly is configured to receive a plurality of surface signals from each of the respective plurality of antenna pairs when the receiver assembly is electronically connected to the plurality of antenna pairs. Each surface signal is indicative of characteristics of the signal received by the respective plurality of antenna pairs. Further, the system includes a computer processor that is configured for electronic communication with the receiver assembly. The computer processor is also configured to determine which among the plurality of surface signals have a preferred signal characteristic. In response to the determination of which surface signal has the preferred signal characteristic, the computer processor decodes the surface signal received by one of the plurality of antenna pairs that received the signal with the preferred signal characteristic.
Another embodiment of present disclosure includes a drilling system for forming a borehole in an earthen formation. The drilling system includes a drill string carried by a support member and configured to rotate so as to define the borehole along a drilling direction. The drill string includes a drill bit positioned at the downhole end of the drill string and one or more sensors carried by the drill string. The one or more sensors are configured to obtain drilling data. The drill string can include a telemetry tool positioned in an up-hole direction away from the drill bit. The telemetry tool is configured to transmit the drilling data via a signal. The drilling system can include a first pair of antennas configured to receive the signal and a second pair of antennas configured to receive the signal. The first and second pair of antennas are in different locations relative to the support member. The drilling system can also include a receiver assembly electronically connected to the first and second pair of antennas. The receiver assembly is configured to receive the surface signals from each the first and second pair of antennas. The surface signals are indicative of the signal that has been received by each pair of antennas. Further, the drilling system can include at least one computer processor configured to decode one of the surface signals received by the receiver assembly based on one or more preferred characteristics of the surface signals obtained from each of the first and second pairs of antennas.
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 of the disclosure. It should be understood, however, that the application is not limited to the precise arrangements and instrumentalities shown. In the drawings:
Referring to
The computing device 200 can host one or more applications, for instance software applications, that can initiate desired decoding or signal processing, log parameters that indicate the type of formation being drilled through, the presence of liquids, and run other applications that are configured to perform various methods for monitoring and controlling the drilling operation.
The drilling system 1, telemetry system 100 and methods 300 (
Telemetry as used herein refers electromagnetic (EM) telemetry. The telemetry system 100 can be configured to produce, detect, and process an electromagnetic field signal 130. In accordance with the illustrated embodiment, the telemetry system 110 is configured to permit reception and detection of the electrical field component of the electromagnetic field signal 130. In addition, the telemetry system 100 can also be configured to permit reception and detection of the magnetic field component of the electromagnetic field signal 130. Thus, the telemetry tool 40 can be configured to produce an electromagnetic field signal 130, and amplify the electric field component, and alternatively or in addition to, amplify the magnetic field component. Accordingly, the antenna pairs 120 and receiver assembly 110 can be configured to receive, for instance detect, the electric field component of the electromagnetic signal 130. Alternatively or in addition, the antenna pairs 120 and receiver assembly 110 can be configured to receive, for instance detect, the magnetic field component of the electromagnetic signal 130.
Continuing with
Continuing with
Referring to
In various embodiments, the input/output portion 206 includes a receiver of the computing device 200, a transmitter (not to be confused with components of the telemetry tool 40 described below) of the computing device 200, or an electronic connector for wired connection, or a combination thereof. The input/output portion 206 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 200. For instance, the input/output portion 206 can be in electronic communication with the receiver assembly 110.
Depending upon the exact configuration and type of processor, the memory portion 204 can be volatile (such as some types of RAM), non-volatile (such as ROM, flash memory, etc.), or a combination thereof. The computing device 200 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 disks (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 200.
The computing device 200 can contain the user interface portion 208, which can include an input device and/or display (input device and display not shown), that allows a user to communicate with the computing device 200. The user interface 208 can include inputs that provide the ability to control the computing device 200, via, for example, buttons, soft keys, a mouse, voice actuated controls, a touch screen, movement of the computing device 200, visual cues (e.g., moving a hand in front of a camera on the computing device 200), or the like. The user interface 208 can provide outputs, including visual information, such as the visual indication of the plurality of operating ranges for one or more drilling parameters via the display 213 (not shown). 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 208 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 208 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 to require specific biometric information for access to the computing device 200.
Referring to
The computing device 200 and the database 230 depicted in
Returning to
Turning to
Continuing with
The electrode assembly 46 defines an electrode connection 58 with the drill string 6. In the illustrated embodiment, the electrode assembly 46 includes a shaft component 47a and a bow spring component 47b. The bow spring component 47b directly contacts the drill string so as to define an electrically conductive connection with the drill string 6 uphole from the insulator 55. Alternatively, the electrode assembly 46 can include a shaft component 47a and a contact ring assembly (not shown) used for fixed mount tools. In such an alternative embodiment, the contact ring defines an electrical connection between the electrode shaft 47a and drill string 6.
Accordingly, the telemetry tool 40 defines the first electrical or electrode connection 58 with the drill string 6. A downhole component, for instance the stinger 48 as illustrated, can define a second electrical or contact connection 60 with the drill string 6 that is spaced from the first electrical connection 58 along the central longitudinal axis 32. The second electrical connection 60 includes conductive electrical contact with the drill string 6 at a location that is spaced from the insulator 55 in the downhole direction 90. As illustrated, the stinger 48 can include a conductive element that defines the second electrical connection 60 with the mule shoe 50 and the drill string 6. The gap sub 52 thus extends between at least a portion of the first and second electrical connection 58 and 60. The electrode connection 58 is typically referred to in the art as a “gap plus” and the contact connection 60 is typically referred to in the art as the “gap minus.”
The power source 45, which can be a battery or turbine alternator, supplies current to the transmission assembly 44, the electrode assembly 46, and sensors 42. The power source 45 is configured to induce a charge, or voltage across the drill string 6, between 1) the first electrical connection 58 defined by the electrode assembly 46 in contact with the drill string 6 above the insulator 55, and 2) the second electrical connection 60 located below the gap sub 52. When the power source 45 supplies a charge to the electrode assembly 46, the electrode shaft 47a conducts current to the first electrical connection 58 located above the insulator 55 in the gap sub 52. The electrode insulator 59 includes a passageway (not shown) that permits the delivery of current to the electrode shaft 47a. Further, the electrode insulator 59 is configured to block the current delivered to the electrode shaft 47a from flowing back into the transmission assembly 44. When the power source 45 induces the charge, the charge creates the electromagnetic field signal 130. The electric field component becomes positive or negative by oscillating the charge, which creates and causes an electromagnetic field signal 130 to emanate from the telemetry tool 40.
The transmission assembly 44 receives drilling data from the one or more sensors 42 and encodes the drilling data into a data packet. The transmission assembly 44 also includes a power amplifier (not shown) electrically connected to a modulator (not shown). The modulator modulates the data packet into the electromagnetic signal 130 created by the voltage induced across the telemetry tool 40 between the first and second electrical connections 58 and 60. It can be said that the data packet is embodied in the electromagnetic field signal 130. The power amplifier amplifies the voltage induced across the telemetry tool 40. In particular, the power amplifier (not shown) amplifies the electrical field component of the electromagnetic signal 130 such that electric field component of the signal 130 can propagate through the formation 3 to the surface 4 and is received by one or more of the antenna pairs 120a, 120b, and 120c. Alternatively, the transmission assembly 44 can be configured to amplify the magnetic field component of the electromagnetic field signal 130 as needed. As used herein, the electromagnetic field signal 130 can refer to the electrical field component of the signal or the magnetic field component of the signal.
As noted above, the telemetry tool 40 may be connected to one or more sensors 42. The one or more sensors may include directional sensors that are configured to measure the direction and inclination of the well path, and orientation of a tool in the drill string. The sensors can also include formation sensors, e.g. gamma sensors, electrical resistivity, and drilling information sensors, e.g., vibration sensors, torque, weight-on-bit (WOB), temperature, pressures, and sensors to detect operating health of the tool. Drilling data can include: directional data, such as magnetic direction, inclination of the borehole and tool face; formation data, such as gamma radiation, electrical resistivity and other measurements; and drilling dynamics data, including but not limited to, downhole pressures, temperatures, vibration data, WOB, torque. Further, while the BHA 7 may include one or more sensors 42 as noted above, additional downhole sensors may be located along any portion of the drill string 6 for obtaining drilling data. The additional downhole sensors can be in electronic communication with the telemetry tool 40 such that the drill data obtained from the additional downhole sensors can be transmitted to the surface 4. While the telemetry tool may connected to one or more sensors located along the drill string 6, some sensors may be integral to the tool 40. Further, one up to all of the sensors can also be electrically connected to a mud pulse telemetry system, as needed.
One or more telemetry system 100 parameters are adjustable during the drilling operation. Parameter adjustment can improve data acquisition and provide additional flexibility to monitor and adjust transmission settings based on signal characteristics. The telemetry tool 40 has an operating frequency between 2 Hz and 12 Hz, the operating frequency being adjustable during the drilling operation. It should be appreciated that the operating frequency can exceed 12 Hz in some embodiments, or be less than 1 Hz in other embodiments. The telemetry tool 40 is configured to have a data rate between 1 to 12 bits per second (bps). The data rate could be up to or exceed 24 bps. However, higher operating frequencies, such as operating frequencies instance well above 12 Hz, do not propagate well through formation strata and data rates are somewhat limited depending on the specific geology of the formation and depth of the transmission point. In any event, the data rate can be adjusted during the drilling operation. Further, the telemetry tool has an adjustable power output that could be as low as 1 W and up to or even exceed 50 W. In addition, the user can adjust data survey sequences, the data density for higher resolution formation logs, sequence of measurements according to needs of the drilling operation, and encoding methodology employed by the modulation device 114 (discussed below). The ability to adjust any one of the aforementioned parameters provides improves system flexibility for receiving and monitoring signal reception at the surface 4. Parameter adjustability, and the improved signal reception by decoding a signal from a particular antenna pair 102 with preferred signal reception characteristics enables the use of higher data rates that can be used with stronger signals. Thus the telemetry system 100 can provide more measurements, more data points for a particular measurement, or an optimum combination of measurements, in real-time, to the drill operator. Optimal real time measurements of downhole conditions enables the drilling operator to execute the drilling operation at hand efficiently. In addition, by constantly switching and selecting to the preferred signal, it is at times possible to drill deeper and still receive a usable signal at the surface. Lastly, utilizing the preferred signal enables transmitting at lower power levels thus reducing the consumption of batteries, typically the highest operating cost of a system. Any of the parameters discussed in this paragraph are exemplary. As an example of the type of telemetry tool employed in the telemetry system 100, the SureShot EM MWD system, as supplied by APS Technology, Inc.
Referring to
Turning to
Returning to
The demodulation device 114 can decode the data packet carried by the surface signals. In an embodiment, the demodulation device 114 and processor (in the computing device 200 can demodulate the surface signal first into binary data. Then, the binary data is sent to the processing portion of the computing device 200. The binary data is then further processed into drilling information that is then stored in computer memory for access by other software applications, for instance, vibration analysis operations, logging display application, etc. Alternatively, the demodulation device 114 and a processor in the receiver assembly 110 can decode the signal into binary data and process the binary data into drilling information or data. Thus, it should be appreciated that the receiver assembly 110 can be configured to detect, amplify and decode the surface signal with the preferred characteristics. Alternatively, the receiver assembly 110 can be configured to detect and amplify each surface signal, and then transmit the amplified surface signals to the computing device 200 (external to the receiver assembly 110) for decoding. In such an embodiment, the computing device 200, via the processing portions, carries out instructions stored on the computer memory, to decode only one of the amplified signals which has the preferred signal characteristics. Decoding can occur automatically as discussed above, or in response to a command to do so from a drilling operator. In the illustrated embodiment, the demodulation device 114 and/or processor (not shown) decodes only the surface signal among the plurality of surface signals based on a determination of the characteristics of electric field component of the EM signal 130 detected by the antenna pairs 120a, 120b, and 120.
Accordingly, while the telemetry system 100 facilities monitoring multiple signals that are indicative of the electric field component of the EM signal 130 detected by multiple respective antenna pairs 120, the telemetry system 100 decodes, among the plurality of surface signals received by the receiver assembly 110, only one surface signal into drilling data. Such a system results in real time observations signal quality from multiple locations simultaneously. Further, as noted above, the telemetry system 100 can allow the drilling operator to utilize the best or preferred quality signal detected among the multiple antenna pair locations. Further, monitoring of multiple signals, as well as the ability to adjust one or more telemetry parameters, allows the drilling operator to tailor the transmission needs, frequency, power input, to specific data acquisition requirement given well path, formation characteristics, and noise. For instance, power input can be lowered to reduce conserve power resource. Conserving power utilizes power sources more efficiently which could allow the drilling operator to finish the bit run and avoid a costly trip out of the hole to replace a power source.
At the onset of a drilling operation, the telemetry tool 40A and drill bit 14A are located at a first downhole location 140A in the borehole 2 during a first duration of the drilling operation. The first downhole location 140A can be associated with the first location A of the antenna pairs 102a on the surface 4. The telemetry tool 40 generates the electromagnetic field 130a (with data packet encoded therein) and travels through formation strata 66 and 68 toward the surface 4. The electric field component of the EM signal 130 is received, for instance detected, by the first antenna pair 120a. The electromagnetic signal 130a can be referred to as a first EM field signal 130a. The electric filed component of the EM signal 130a could be detected by the second antenna pair 120b as well, though the signal characteristics detected by the second antenna pair 120b may be less preferred than the electric field signal detected by the first antenna pair 120a. It should be appreciated that the downhole location of the telemetry tool 40 during the drill operation is not required to be directly beneath the location A along the vertical direction V. As the first EM field signal 130a travels through the formation 3, formation strata, noise from the derrick 5, motors, metallic components, underground utilities transmission lines, impacts the electric field component and reduces the detectable signal at the surface 4. Formation strata can be favorable or unfavorable to signal transmission to varying degrees. As the well progresses it may pass through or under formation strata which have different degrees of favorability for signal transmission and reception. This constantly changing environment may require frequent adjustments to the location of the antennas (in conventional system) and operating parameters. Further, background electrical noise may come and go according to surface activities. By being able to observe signal quality in real time from multiple locations via antenna pairs 120, and switching among the antenna pair locations for optimum signal quality in a timely manner is beneficial.
As drilling progresses, the borehole 2 changes orientation from a more vertical direction V into a more horizontal direction H. Thus, during a second duration of the drilling operation that is subsequent to the first duration of the drilling operation, the telemetry tool 40 can generate a second EM field signal 130b that emanates from the telemetry tool 40 located at the second downhole location 140B in the borehole 2 that is downhole with respect to the first downhole location 140A. When the telemetry tool 40 is at the second downhole location 140B, the second EM field signal 130b travels through formation strata 62, 64, 66, and 68 toward the surface 4. The second EM field signal 130b is detected by the antenna pairs 120b and 120c. Thus, the downhole location 140B is located at a greater depth from the surface 4 than the downhole location 140A. As noted above, the electromagnetic signal 130b attenuates as the electromagnetic 130b emanates from the telemetry tool 40 and travels to the surface 4.
As the electromagnetic field signal 130b approaches the surface 4, noise and the formation strata, impacts the electromagnetic signal and degrades the detectable signal at the antenna pairs 120a, 120b and/or 120c. Depending on the location of the antenna pair relative to the telemetry tool 40 in the borehole 2, for instance, the antenna pair 120b may receive and detect the electric field component of the signal 130b with a lower (worse) signal to noise ratio compared to the signal to noise ratio of the electric field component of the signal 130b detected by antenna pair 120c because at 120c the signal 130b passes through a thinner part of an unfavorable strata 68. In operation, because the surface signals of each respective antenna pairs 120a, 120b, and 120c, which are indicative of the electric field component of the second EM signal 130b, are displayed via the computer display, a drilling operator has real-time visual indication of the relative strength of the electric field signal detected at each antenna pair. The operator can cause the computing device 200 to decode, via the demodulation device 114, only that surface signal that has preferred signal characteristics. Alternatively, the computing device 200, running software stored on the memory portion, causes the processor to determine signal characteristics for each signal received from each antenna pair 120a, 120b, and 120c. On the basis of the preferred signal characteristics, the computing device 200 causes the demodulation device 114 to automatically decode the surface signal with the preferred signal characteristics into drilling data that can be used with one or more software applications to monitor and control the drilling operation.
Whether one or more of the antenna pairs detect the first EM field signal 130a or the second EM field signal 130b, the electric field signal detected by the first and second pair of antennas have respective first and second signal characteristics. The system, apparatus and method as described herein can identify which of the first and second signal characteristics the electric field signal detected by the respective first and second pairs of antennas is a preferred signal characteristic. Thus, only the surface signal detected or monitored by only one of the pair of antennas 120a, 120b, 120c that detected the electric field signal with the preferred signal characteristic is decoded, as further detailed below.
Referring to
In step 316, one or more up to all of the plurality of antenna pairs 120a-120c detect the signal 130. The antenna pairs 120 detect the signal as an alternating voltage indicative of a waveform. The waveform embodies the data packet encoded into the signal 130 downhole. The voltage detected by the antenna pairs 120 is referred to as a surface signal, as noted above. In turn, in step 320, the receiver assembly 110 receives the surface signal from each respective antenna pair 120a, 120b, or 120c. As noted above, more than three pairs of antennas 120 can be used. Process control is then transferred to step 324 (
Returning to step 324, process control can also be transferred to step 328, whereby the processor determines if automatic signal selection has been overridden. For example, the user may want to select which surface signal should be decoded. The processor determines if the operator has 1) manually selected a surface signal with the preferred signal characteristics, or 2) has indicated that auto signal selection is not needed. If there is an automatic signal override, process control is transferred to step 356 described above. If there has not been an automatic signal override, process control is transferred to step 332.
In step 332, the selected surface signal with the preferred signal characteristics is decoded into drilling data. The processor can cause the demodulation device 114 to decode the surface signal received from the antenna pair that has detected the signal with the preferred signal characteristics. For instance, if the surface signal from antenna pair 120b has preferred signal characteristics over the surface signal received from antenna pair 120c, then the demodulation device 114 will decode the surface signal received from antenna pair 120c. As noted above, decoding can include two phases: 1) processing the data packet into binary data, and 2) processing binary data into drilling information. Either decoding phase, or both decoding phases, can be carried out via processor housed in the receiver assembly 110. Alternatively, either decoding phase, or both decoding phases, can be carried out via processor housed in the computing device 200.
In step 336, the processor will continuously determine which surface signal has the preferred signal characteristics over a period of time (t). The period of time (t) can be very short. As the drill string 6 advances through the formation 3, the antenna pair 120b receives a surface signal with the preferred signal characteristics. Over time, however, antenna pair 120c detects the signal 130 with preferred signal characteristics over the signal as detected from antenna pair 120b. Thus, if the selected surface signal is the surface signal with the preferred signal characteristics, process control is transferred to step 340. If the selected surface signal is no longer the surface signal with the preferred signal characteristics, process control is transferred to step 323.
In step 340, the decoded signal is transmitted to the computing device 200 or portions thereof. In step 344, the computing device 200, via one or applications hosted thereon, determines drilling operation information from the decoded drilling data.
Referring to
In accordance with the alternate embodiment, in step 424, the process determines the signal to noise ratio for each signal received from the antenna pairs 120. In step 432, the surface signal from the antenna pair that detects the signal 130 with the highest signal to noise ratio is selected. Either the user can select the signal with the highest signal to noise ratio or the processor can automatically select the signal with the highest signal to noise ratio. For instance, the method 400 can also include a manual override detection step, similar to step 328 discussed above. In step 436, the selected surface signal is decoded. The processor can cause the demodulation device 114 to decode the surface signal received from the antenna pair that has received the signal with the highest signal to noise ratio. In step 440, the decoded signal is transmitted to the computing device 200 or a processor included in the receiver assembly 110. In step 440, the computing device 200 determines the drilling operation information from the decoded drilling data as discussed above. The method 400 can also include the step of displaying each surface signal via display (not shown).
In accordance with another embodiment of the present disclosure, the telemetry system 100 can be configured to downlink information from the surface 4 to the tool located downhole, such as the telemetry tool 40. The downlink telemetry system 100 (not shown) when configured for downlinking data to the telemetry tool 40, can include a receiver assembly 510 (not shown) and plurality of antenna pairs 520 (not shown), similar to the embodiment described above. However, in accordance with the alternate embodiment, the receiver assembly 110 can be housed in a downhole tool telemetry tool 40 or some other tool or drill string component. Further, the plurality of antenna pairs 520 can be positioned along the drill string 6. At the surface 4, the downlink telemetry system 100 can include a transmitter 544 (not shown). For instance, the transmitter 544 can be included in the receiver assembly 110 or can be a separate unit. The transmitted is configured to encode data received from a source, such as sensors or a computing device, into an electromagnetic field signal that propagates into the formation. The receiver assembly 210 and plurality of antenna pairs 520 will function in similar manner to receiver assembly 110 and plurality of antenna pairs 520 described above.
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