Patent Application
20100195442
The present invention relates generally to well drilling operations and, more particularly, to data communications between downhole equipment and surface equipment during such drilling operations.
During certain well drilling processes, it may be desirable to communicate information from the bottom of the wellbore to the surface. For instance, logging-while-drilling (LWD) and measurement-while-drilling (MWD) techniques may generally include the collection of a number of various measurements via one or more sensors within the wellbore. Data collected through such techniques may include measurements related to characteristics of the wellbore (e.g., azimuth and inclination) or drilling components (e.g., rotational speed) themselves, or measurements pertaining to the properties of geologic formations (e.g., density, pressure, or resistivity) proximate the wellbore, for example.
The measured data may be communicated to the surface through mud pulse telemetry techniques, in which drilling fluid or “mud” is used as a propagation medium for a signal wave, such as a pressure wave. More specifically, data may be communicated by modulating one or more features of the wave to represent the data. For instance, the amplitude, the frequency, and/or the phase of the wave may be varied such that each variation represents either a single data bit (i.e., binary modulation) or multiple data bits (i.e., non-binary modulation) of digital data. As the wave propagates to the surface, these modulations may be detected and the data bits may be determined from the modulations.
It is noted, however, that the characteristics of the downhole modulator used and the mud pulse telemetry channel itself may impact communication rates, power, bandwidth, and accuracy of various modulation techniques. For instance, in a phase shift keying (PSK) modulation technique digital data is generally impressed onto the wave in the mud by modulating the phase of the wave from within the wellbore. A demodulator at the surface detects the phase and reconstructs the digital data.
While PSK modulation generally calls for abrupt (in fact, instantaneous in the ideal case) changes of phase, it will be appreciated by those skilled in the art that the above-described modulator cannot generate instantaneous phase changes. Instead, mud pulse telemetry systems employing PSK modulation typically approximate the abrupt phase changes by making phase changes to the wave as quickly as mechanically allowed by the downhole modulator. Although controlling the modulator to implement phase changes as quickly as physically possible does enable data to be communicated via certain lower-order PSK techniques (e.g., binary PSK), it is believed that such control does not effectively allow data to be communicated via other higher-order PSK techniques (e.g., 8-PSK, in which eight discrete phases are used to represent various data groups having three bits each).
Certain aspects of embodiments disclosed herein by way of example are summarized below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of certain forms an invention disclosed and/or claimed herein might take, and that these aspects are not intended to limit the scope of any invention disclosed and/or claimed herein. Indeed, any invention disclosed and/or claimed herein may encompass a variety of aspects that may not be set forth below.
The present disclosure generally relates to techniques for communicating data by modulating an acoustic wave in a mud pulse telemetry system. In accordance with one disclosed embodiment, the acoustic wave is modulated to represent data in accordance with a PSK technique employing non-binary modulations with smooth transitions. In certain embodiments, the acoustic wave is further modulated in accordance with error checking and/or correction techniques, such as trellis coded modulation techniques.
Various refinements of the features noted above may exist in relation to various aspects of the present invention. Further features may also be incorporated in these various aspects as well. These refinements and additional features may exist individually or in any combination. For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present invention alone or in any combination. Again, the brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of embodiments of the present invention without limitation to the claimed subject matter.
These and other features, aspects, and advantages of the present invention will become better understood when the following detailed description of certain exemplary embodiments is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:
One or more specific embodiments of the present invention will be described below. These described embodiments are only examples of the present invention. Additionally, in an effort to provide a concise description of these exemplary embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
When introducing elements of various embodiments of the present invention, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Moreover, while the term “exemplary” may be used herein in connection to certain examples of aspects or embodiments of the presently disclosed subject matter, it will be appreciated that these examples are illustrative in nature and that the term “exemplary” is not used herein to denote any preference or requirement with respect to a disclosed aspect or embodiment. Further, any use of the terms “top,” “bottom,” “above,” “below,” other positional terms, and variations of these terms is made for convenience, but does not require any particular orientation of the described components.
Turning now to the drawings, and referring first to
During a drilling process, various debris (e.g., drill cuttings) may collect near the bottom of the wellbore 16. Additionally, the temperature of the drill bit 18 may increase due to friction between the drill bit 18 and the drilled geologic formation. Consequently, a drilling fluid 22, commonly referred to as drilling “mud”, may be cycled through the wellbore 16 to remove such debris and facilitate cooling of the drill bit 18. In the presently illustrated embodiment, the drilling fluid 22 may be pumped from a reservoir or “mud pit” 24 and pumped through the wellbore 16 via a pump 26. More particularly, the pump 26 may route drilling fluid 22 through supply conduits 28 (e.g., pipes or hoses) to the drill string 14, as generally depicted by the arrows 30. The drilling fluid may flow downwardly through the drill string 14 to a distal end, as generally indicated by the arrows 32, and may exit the drill string 14 at or near the drill bit 18.
The drilling fluid 22 may then return to the surface through an annulus 34 generally defined between the circumference of the wellbore and the drill string 14, as indicated by arrows 36. Finally, the drilling fluid may exit the wellbore 16 via a return conduit 38, which routes the drilling mud 22 back to the reservoir 24 as generally depicted by arrows 40. In this manner, drilling fluid 22 routed through the wellbore 16 may cool the drill bit 18 and remove debris from the wellbore 16. Additionally, the debris in the drilling fluid 22 returning to the reservoir 24 from the wellbore 16 may settle to the bottom of the reservoir 24, allowing the drilling fluid 22 to be recycled through the wellbore 16.
As will be appreciated, various additional components and tools may be provided in the wellbore 16, such as components configured to facilitate MWD or LWD operations. In one embodiment, such additional components disposed in the wellbore 16 may include one or more data sources 42. The data sources 42 may include, for instance, various instruments or sensors configured to measure information relevant to a drilling process. Examples of such information include position data, orientation data, pressure data, and gamma ray data, although the use of sensors to measure other parameters is also envisaged.
Data collected from the one or more data sources 42 may be electronically transmitted to an assembly including an encoder 44 and a modulator 46, which cooperate to generate an acoustic wave (e.g., a pressure wave) and to vary aspects of the wave to represent the data from the one or more data sources 42, as discussed in greater detail below. The wave propagates through the drilling fluid 22 in the drill string 14 and the supply conduit 28 (which may include a standpipe of the drilling rig 12), as generally indicated by the arrows 50. The variations in the wave may be detected by one or multiple sensors 52 (e.g., pressure transducer(s)) at the surface of the system 10.
The detected variations may be processed by a computer 54 to reconstruct the original data from the one or more data sources 42. As will be appreciated, in one embodiment the computer 54 may include a processor configured to execute one or more programs stored within a memory of the computer to correlate the wave modulations with sequences of bits of the original digital data from the one or more data sources 42. It is further noted, however, that an application-specific integrated circuit may instead provide or supplement such functionality. Additionally, the computer 54 may also facilitate control and/or monitoring of other aspects of the system 10. For instance, in one embodiment, the computer 54 may facilitate control of the pump 26.
Exemplary components of a modulator 46 are generally illustrated in
The rotor 62 may rotate with respect to a stator 64 of the rotary valve 56 to selectively inhibit the flow of drilling fluid 22 through the rotary valve 56 and to generate pressure pulses (e.g., the acoustic wave) as discussed above. For instance, the rotor 62 and the stator 64 may include complimentary openings that allow drilling fluid 22 to flow through the rotary valve 56 when the rotor 62 is oriented in an “open” position, and that prevent such flow when the rotor 62 is oriented in a “closed” position. In one embodiment, the selective inhibition of the flow of drilling fluid 22 results in a continuous pressure wave, having a period proportional to the rate of interruption, that propagates upwardly from the rotary valve 56 to the surface through the drilling fluid 22.
With fine control of the motor 58, the absolute position of the valves 56 and 59 discussed above may be better controlled. Any suitable motor control techniques may be employed in conjunction with the presently disclosed subject matter, including those disclosed in, for example, U.S. Pat. Nos. 6,327,524 and 7,129,673, and U.S. Pat. Appl. Pub. No. 2005/0263330, each of which is incorporated herein by reference in its entirety.
The modulation and demodulation of data, and communication of the data from the bottom of the wellbore 16 to the surface, is generally depicted in
The modulator 74 is configured to modulate the pressure wave 76 in accordance with the symbols provided by the encoder 72. Although an example is provided below in connection with a PSK modulation technique, it is noted that numerous other modulation techniques could be employed in addition to, or instead of, PSK modulation. Examples of such other modulation techniques include amplitude modulation (AM), frequency modulation (FM), minimum shift keying (MSK), frequency shift keying (FSK), phase modulation (PM), continuous phase modulation (CPM), quadrature amplitude modulation (QAM), and trellis code modulation (TCM). The pressure wave 76 may then be received by a demodulator/decoder 78, such as the sensor 52 and computer 54 (
A more detailed example of this process is described below with reference to
By way of further example, and as generally illustrated in
In addition to a PSK modulation technique, in some embodiments the data may also be encoded in accordance with a smooth phase interpolation technique, in which transitions between phases are made in a controlled and smooth manner, rather than made as quickly as mechanically allowed by the modulator 74. In one embodiment, the wave signal for a smooth phase PSK modulation may be represented as:
where Es is the energy per symbol, T is the symbol period, fc is the carrier frequency, q(.) is a transition function, σ(n) is the state of the modulator at time nT, and Θm is one of m discrete phase levels to be reached.
One way of generating the transition function, q(.), has been described in Borah, D. K., “Smooth Phase Interpolated Modulations for Nonlinear Channels”, Proc. IEEE Global Commun. Conf., GLOBECOM '2004, vol. 1, pp 10-14 (2004), which is incorporated herein by reference in its entirety. In some embodiments, the transition functions may take the full symbol period to reach the desired phase level. In other embodiments, however, transition functions using only a fractional portion of the symbol period, such as substantially equal to one-half or one-quarter of the symbol period, to reach the desired phase level may be employed. In addition, other ways of generating the phase transition are also envisioned.
In at least some embodiments, using smooth phase transitions may reduce the energy of the signal outside its main band. Such a reduction in the energy outside the main band of the signal may facilitate the sharing of the signal spectrum between multiple modulators without them interfering with each other. In addition, it is noted that using higher-order, M-ary, PSK techniques (e.g., 8-PSK rather than 4-PSK), wherein M represents the number of discrete phases, may also reduce the bandwidth of the signal for a fixed bitrate. Additionally, these smooth phase transition modulation techniques generally reduce the power requirements of, and mechanical strain on, the modulator. Consequently, higher telemetry rates and smaller bit error rates can be achieved.
Further, in some embodiments various error checking and/or correcting codes may also be incorporated in the modulation process. For instance, one embodiment may include the use of trellis coded modulation (TCM) in conjunction with an 8-PSK modulation technique, which may achieve a bit error rate of 0.01% at a relatively low signal-to-noise ratio of less than 6.5 dB, compared to the approximate 8.5 dB ratio that may be required to achieve the same error rate using 4-PSK alone, and the approximate 11.5 dB ratio that may be required to achieve the same error rate using 8-PSK alone. Still further, it is noted that in at least some embodiments, the use of absolute PSK modulation (in which each phase modulation is measured through comparison of a present phase to that of an original reference signal), rather than differential PSK (in which each phase modulation is measured through comparison of a present phase to that of the previous symbol) may further reduce the error rate when employing systematic convolutional error-correcting codes.
The method 90 of
A graph 120 representative of the modulations discussed above with respect to steps 102, 106, and 110 is generally provided in
The phase of the pressure wave may be maintained at π/8 for the remaining portion 134 of the first symbol period, and may then be modulated in a transition portion 138 of the second symbol period to θ=9π/8, which, as discussed above, generally represents the data sequence “110” of the group 96. Once this transition is complete (i.e., when the difference 142 between the curve 128 and the reference curve 126 is 9π/8), the phase may be maintained at this level for the remaining portion 140 of the second symbol period. The pressure wave may again be modulated in a transition portion 144 of a third symbol period (e.g., from θ=9π/8 to θ=5π/8, representative of the data of group 98), and the phase of 5π/8 may be maintained throughout the remaining portion 146 of the third symbol period. The phase of 5π/8 is generally depicted as the difference 148 between the curves 126 and 128.
While the invention may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the invention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims.
