Communications: electrical – Wellbore telemetering or control – Pulse or digital signal transmission
Reexamination Certificate
2000-02-21
2003-06-24
Edwards, Timothy (Department: 2635)
Communications: electrical
Wellbore telemetering or control
Pulse or digital signal transmission
C340S854400, C367S082000
Reexamination Certificate
active
06583729
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates to a telemetry system for transmitting data from a downhole drilling assembly to the surface of a well. More particularly, the present invention relates to a system and method for improved acoustic signaling through a drill string.
2. Description of the Related Art
Modem petroleum drilling and production operations demand a great quantity of information relating to parameters and conditions downhole. Such information typically includes characteristics of the earth formations traversed by the wellbore, along with data relating to the size and configuration of the borehole itself. The collection of information relating to conditions downhole, which commonly is referred to as “logging”, can be performed by several methods.
In conventional oil well wireline logging, a probe or “sonde” housing formation sensors is lowered into the borehole after some or all of the well has been drilled, and is used to determine certain characteristics of the formations traversed by the borehole. The upper end of the sonde is attached to a conductive wireline that suspends the sonde in the borehole. Power is transmitted to the sensors and instrumentation in the sonde through the conductive wireline. Similarly, the instrumentation in the sonde communicates information to the surface by electrical signals transmitted through the wireline.
The problem with obtaining downhole measurements via wireline is that the drilling assembly must be removed or “tripped” from the drilled borehole before the desired borehole information can be obtained. This can be both time-consuming and extremely costly, especially in situations where a substantial portion of the well has been drilled. In this situation, thousands of feet of tubing may need to be removed and stacked on the platform (if offshore). Typically, drilling rigs are rented by the day at a substantial cost. Consequently, the cost of drilling a well is directly proportional to the time required to complete the drilling process. Removing thousands of feet of tubing to insert a wireline logging tool can be an expensive proposition.
As a result, there has been an increased emphasis on the collection of data during the drilling process. Collecting and processing data during the drilling process eliminates the necessity of removing or tripping the drilling assembly to insert a wireline logging tool. It consequently allows the driller to make accurate modifications or corrections as needed to optimize performance while minimizing down time. Designs for measuring conditions downhole including the movement and location of the drilling assembly contemporaneously with the drilling of the well have come to be known as “measurement-while-drilling” techniques, or “MWD”. Similar techniques, concentrating more on the measurement of formation parameters, commonly have been referred to as “logging while drilling” techniques, or “LWD”. While distinctions between MWD and LWD may exist, the terms MWD and LWD often are used interchangeably. For the purposes of this disclosure, the term MWD will be used with the understanding that this term encompasses both the collection of formation parameters and the collection of information relating to the movement and position of the drilling assembly.
When oil wells or other boreholes are being drilled, it is frequently necessary or desirable to determine the direction and inclination of the drill bit and downhole motor so that the assembly can be steered in the correct direction. Additionally, information may be required concerning the nature of the strata being drilled, such as the formation's resistivity, porosity, density and its measure of gamma radiation. It is also frequently desirable to know other downhole parameters, such as the temperature and the pressure at the base of the borehole, for example. Once this data is gathered at the bottom of the borehole, it is necessary to communicate it to the surface for use and analysis by the driller.
Sensors or transducers typically are located at the lower end of the drill string in LWD systems. While drilling is in progress these sensors continuously or intermittently monitor predetermined drilling parameters and formation data and transmit the information to a surface detector by some form of telemetry. Typically, the downhole sensors employed in MWD applications are positioned in a cylindrical drill collar that is positioned close to the drill bit. The MWD system then employs a system of telemetry in which the data acquired by the sensors is transmitted to a receiver located on the surface. There are a number of telemetry systems in the prior art which seek to transmit information regarding downhole parameters up to the surface without requiring the use of a wireline tool. Of these, the mud pulse system is one of the most widely used telemetry systems for MWD applications.
The mud pulse system of telemetry creates “acoustic” pressure signals in the drilling fluid that is circulated under pressure through the drill string during drilling operations. The information that is acquired by the downhole sensors is transmitted by suitably timing the formation of pressure pulses in the mud stream. The information is received and decoded by a pressure transducer and computer at the surface.
In a mud pressure pulse system, the drilling mud pressure in the drill string is modulated by means of a valve and control mechanism, generally termed a pulser or mud pulser. The pulser is usually mounted in a specially adapted drill collar positioned above the drill bit. The generated pressure pulse travels up the mud column inside the drill string at the velocity of sound in the mud. Depending on the type of drilling fluid used, the velocity may vary between approximately 3000 and 5000 feet per second. The rate of transmission of data, however, is relatively slow due to pulse spreading, distortion, attenuation, modulation rate limitations, and other disruptive forces, such as the ambient noise in the drill string. A typical pulse rate is on the order of a pulse per second (1 Hz).
Given the recent developments in sensing and steering technologies available to the driller, the amount of data that can be conveyed to the surface in a timely manner at 1 bit per second is sorely inadequate. As one method for increasing the rate of transmission of data, it has been proposed to transmit the data using vibrations in the tubing wall of the drill string rather than depending on pressure pulses in the drilling fluid. However, early systems have proven to be unreliable at data rates greater than about 3 bits/s due to acoustic reflections at tool joints and variations in the geometry of the tubing and borehole.
SUMMARY OF THE INVENTION
Accordingly, there is disclosed herein a reliable downhole acoustic telemetry system with increased data rate. In one embodiment, the telemetry system includes a receiver having an envelope-detection demodulator and a multipulse block distance detector. The envelope-detection demodulator converts a bandpass signal into a baseband envelope signal. The distance detector compares the baseband envelope signal to stored waveforms, and indicates for each symbol interval the multipulse block having the waveform closest to the baseband envelope signal. The distance detector may use any distance metric, including absolute value and even powers of the difference between the baseband envelope signal and the stored waveforms. The receiver may also include a timing recovery module that models the baseband envelope signal for the detected multipulse blocks and determines a distance for early-sampling and late-sampling of the baseband envelope signal. The timing recovery module then provides a sampling clock that minimizes the average difference between the early- and late-sampling distances.
The telemetry system may further include a transmitter having an encoder and a modulator. The encoder converts a data signal into a sequence of multipulse blocks having a settling interval between the blocks. The modulator modu
Gardner Wallace R.
Kyle Donald
Shah Vimal V.
Edwards Timothy
Halliburton Energy Service,s Inc.
Kruegger Daniel J.
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