Wells are generally drilled into the ground to recover natural deposits of hydrocarbons and other desirable materials trapped in geological formations in the Earth's crust. A well is typically drilled using a drill bit attached to the lower end of a drill string. The well is drilled so that it penetrates the subsurface formations containing the trapped materials and the materials can be recovered.
At the bottom end of the drill string is a “bottom hole assembly” (“BHA”). The BHA includes the drill bit along with sensors, control mechanisms, and the required circuitry. A typical BHA includes sensors that measure various properties of the formation and of the fluid that is contained in the formation. A BHA may also include sensors that measure the BHA's orientation and position.
The drilling operations may be controlled by an operator at the surface or operators at a remote operations support center. The drill string is rotated at a desired rate by a rotary table, or top drive, at the surface, and the operator controls the weight-on-bit and other operating parameters of the drilling process.
Another aspect of drilling and well control relates to the drilling fluid, called “mud”. The mud is a fluid that is pumped from the surface to the drill bit by way of the drill string. The mud serves to cool and lubricate the drill bit, and it carries the drill cuttings back to the surface. The density of the mud is carefully controlled to maintain the hydrostatic pressure in the borehole at desired levels.
In order for the operator to be aware of the measurements made by the sensors in the BHA, and for the operator to be able to control the direction of the drill bit, communication between the operator at the surface and the BHA are necessary. A “downlink” is a communication from the surface to the BHA. Based on the data collected by the sensors in the BHA, an operator may desire to send a command to the BHA. A common command is an instruction for the BHA to change the direction of drilling.
Likewise, an “uplink” is a communication from the BHA to the surface. An uplink is typically a transmission of the data collected by the sensors in the BHA. For example, it is often important for an operator to know the BHA orientation. Thus, the orientation data collected by sensors in the BHA is often transmitted to the surface. Uplink communications are also used to confirm that a downlink command was correctly understood.
One common method of communication is called “mud pulse telemetry.” Mud pulse telemetry is a method of sending signals, either downlinks or uplinks, by creating pressure and/or flow rate pulses in the mud. These pulses may be detected by sensors at the receiving location. For example, in a downlink operation, a change in the pressure or the flow rate of the mud being pumped down the drill string may be detected by a sensor in the BHA. The pattern of the pulses, such as the frequency, the phase, and the amplitude, may be detected by the sensors and interpreted so that the command may be understood by the BHA.
Mud pulse systems are typically classified as one of two species depending upon the type of pressure pulse generator used, although “hybrid” systems have been disclosed. The first species uses a valving “poppet” system to generate a series of either positive or negative, and essentially discrete, pressure pulses which are digital representations of transmitted data. The second species, an example of which is disclosed in U.S. Pat. No. 3,309,656, comprises a rotary valve or “mud siren” pressure pulse generator which repeatedly interrupts the flow of the drilling fluid, and thus causes varying pressure waves to be generated in the drilling fluid at a carrier frequency that is proportional to the rate of interruption. Downhole sensor response data is transmitted to the surface of the earth by modulating the acoustic carrier frequency. A related design is that of the oscillating valve, as disclosed in U.S. Pat. No. 6,626,253, wherein the rotor oscillates relative to the stator, changing directions every 180 degrees, repeatedly interrupting the flow of the drilling fluid and causing varying pressure waves to be generated.
FIG. 1 illustrates a continuous carrier wave generating rotating siren of the second species. As can be seen in FIG. 1, when the rotor 100 and stator 102 are in streamline registry, the siren is fully open, and when the rotor 100 and stator 102 are in streamline interference, the siren is closed, generating the pressure pulse generated as a function of time. In such a configuration, the signal strength is defined by the ratio of the open area to the closed area. Erosion resistance depends on the closed area, and shock resistance depends on the clearance of the blades between the rotor 100 and the collar 104.
The design of a modulator is a trade-off between signal strength, subjectivity to jamming, erosion, and shock performance—it is desirable to increase signal strength while limiting erosion, jamming, and shock resistance.
U.S. Pat. No. 5,583,827 to Chin, entitled “Measurement While Drilling System and Method” discloses a plurality of modulator sirens in tandem to increase the data transmission rate, each of the modulators having a variable gap between the rotor and stator that enables amplitude modulation (i.e., either the rotor or the stator is axially moveable relative to the other).
U.S. Pat. Nos. 5,740,126 and 5,586,083 to Chin et al., both entitled “Turbo Siren Signal Generator for Measurement While Drilling Systems,” disclose a plurality of modulator assemblies each having a different number of lobes so as to operate at different distinct frequencies, thereby providing a plurality of transmission channels. It is desirable, however, to provide improved single strength along a single transmission channel.