This invention relates to wellbore communication systems and particularly to systems and methods for generating and transmitting data signals to the surface of the earth while drilling a borehole, wherein the transmitted signal is generated by a multi-stage stacked modulator.
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.
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.
In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments are possible.
Still referring to
As described previously, pulse generator assemblies are typically classified as one of two species depending upon the type of modulator device (i.e., valve) used. The first species uses a valving system, or “poppet” valve to generate a series of either positive or negative, and essentially discrete, pressure pulses which are digital representations of the transmitted data. The second species comprises a rotary valve, “mud siren,” or oscillating pressure pulse generator, which repeatedly restricts the flow of the drilling fluid, and causes varying pressure waves to be generated in the drilling fluid at a 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. The pulse generator assembly 36 of the present invention may include a plurality of valve assemblies or stages of either species, as will be described in greater detail below.
Generating the pressure signal from the multi-stage modulator of the present disclosure as close to a sine wave as possible is advantageous since the energy put into generating the pressure signal is useful for actually accomplishing telemetry. There are several ways to accomplish this; one way is to design the multi-stage rotors and stators shapes such that when synchronously rotating or oscillating the rotors at a constant rotational speed, the pressure wave generated while flowing the fluid at a substantially constant flow through the modulator will generate a sine wave pressure variation. Another way is to control the the instantaneous synchronized rotors' speed by the control circuitry compensating for any deviations from sine wave pressure generation. In one embodiment, the control circuitry is a microcomputer with motor or actuator drive electronics and software instructions controlling the rotors' movement based on feed-back mechanisms described herein. The feed-back for control mechanism can be based on a model of the instantaneous variations in synchronized rotational speed needed, at a position, given the designs of the multi-stage modulator rotors' and stators' shapes. Another way is to measure actual differential pressure across the modulator and feed back this to control the rotational speed.
Alternatively, in other embodiments, the stages 300A-D might include rotor and stator pairs with differing number of lobes compared to the other individual stages in the series. For example, 300A and 300C might include 3 lobes in the rotors and stators, while 300B and 300D would include 6 lobes. In such a configuration, the frequency of rotation of stages 300B and 300D would be different from the frequency of rotation of stages 300A and 300C in order to maintain vertical alignment (for at least partial overlap) for the flow orifice through the series. Specifically, in the example of 300A and 300C having 3 lobes in the rotors and stators, and 300B and 300D having 6 lobes in the rotors and stators, 300A and 300C would be operated at a first frequency f1, 300B and 300D would be operated at a second frequency f2, and f2=½f1, since the number of rotor/stator lobes in B and D is twice the number of rotor/stator lobes in A and C. Such a configuration enables at least one method of amplitude modulation with increased signal strength. Any combination of numbers of lobes and frequencies, as long as synchronization (as described herein) is maintained, is envisioned.
On the right in
The signal strength for a single transmission channel is multiplied by the number of stages 300A-D employed in the multi-stage pulse generator assembly. For the particular embodiment shown in
In various embodiments, a series of as few as two stages could be employed together, and synchronized, resulting in a signal strength multiplied by 2, relative to a single stage modulator of the prior art, as shown in
In still another embodiment, amplitude modulation may also be achieved by differing the direction of rotation of at least one of the stages in the series relative to the others. Specifically, the same signal strength enhancement described above can be achieved if one or more of the stages' rotors are rotating in the opposite direction to the direction of rotation of at least one other stage's rotor, or, for example, if oscillating valves are employed, having rotors that change the direction of rotation periodically, such as every 180 degrees. As long as the synchronization is maintained, such that the at least partial overlap is maintained to produce the flow orifice described above, the signal strength enhancement is achieved.
In still another embodiment, amplitude modulation may be achieved in still another manner as is explained with reference to
It is envisioned that any combination of frequency, phase, or amplitude modulation may be enabled by incorporation of the multi-stage modulator of the present disclosure.
Alternatively, in
In
The various sine waves shown in
As to the relative placement of the stages along the shaft(s), the distance between each successive stage should be significantly less than the wavelength of the frequency of the generated wave. For example, in a preferred embodiment, the distance between stages would be significantly less than 160 feet, which is approximately the wavelength at 24 Hz. The stages also would be placed at least far enough from one another so as to minimize the effect of turbulence in the drilling fluid. In various embodiments, this minimum separation would be at least three (3) inches apart depending on the geometry of the flow section. In at least some embodiments, to further minimize turbulence between stages, one or more fins can be added to the rotors of each respective stage as would be well known by one of ordinary skill in the art.
Since the signal strength can be dramatically increased with the multi-stage modulator, anti-jamming, erosion, and shock can be improved upon at the cost of some of the added signal strength. Improved anti-jamming and improved erosion can be achieved by increasing the tip clearance between the rotor edge and the surrounding rum, or increasing the gap between the rotor and stator. Additionally, though somewhat less desirable, the ratio of the open area to the closed area defining the flow orifice through the modulator can be increased. Such means of improving anti-jamming, and resistance to erosion and shock have previously been recognized, but not typically adopted in design due to the cost in signal strength, however, with the increased signal strength provided by the multi-stage modulator, such means can be implemented while still enjoying increased signal strength over single stage modulator designs.
Specifically, the multi-stage modulator of the present disclosure enables improved anti-jamming. When the signal strength level is adequate, by stacking a plurality of stages, the configuration offers a high level of resistance to jamming. Specifically, this can be achieved by increasing the tip clearance between the rotor edge and the rim surrounding the rotor (which is typically 0.03 inch to 0.1 inch).as well as the gap between the rotor and the stator (which is typically 0.1 inch). In preferred embodiments, the gap between the rotor and stator is a fixed distance once the assembly has been assembled and/or placed in the wellbore.
Additionally, opening the closed area of a stage to reduce the effects of erosion and shock in a dual (or multiple) stage modulator significantly improves the erosion and shock performance while achieving increases in signal strength. When erosion is a lesser issue, the multi-stage modulator increases the signal by 6 dB, corresponding to a quadrupled data rate in certain conditions.
The same technique of staging multiple valves in series can be applied to poppet valve style modulators to create positive or negative pulse telemetry systems, if the valves do not close entirely, but permit at least a minimal flow through in the “closed” position.
While the invention has been disclosed with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover such modifications and variations as fall within the true spirit and scope of the invention.
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Entry |
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Search Report for the equivalent European patent application No. 10156119.9 issued on Jan. 4, 2013. |
Number | Date | Country | |
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20100230113 A1 | Sep 2010 | US |