Patent Application
20110286308
None.
The present invention relates generally to a downlinking system for transmitting data and/or commands from the surface to a downhole tool deployed in a drill string. Exemplary embodiments of this invention relate to a downlinking method in which a downlinking signal includes at least a synchronization phase and a command phase.
Oil and gas well drilling operations commonly make use of logging while drilling (LWD) sensors to acquire logging data as the well bore is being drilled. This data may provide information about the progress of the drilling operation or the earth formations surrounding the well bore. Significant benefit may be obtained by improved control of downhole sensors from the rig floor or from remote locations. For example, the ability to send commands to downhole sensors that selectively activate the sensors can conserve battery life and thereby increase the amount of downhole time a sensor is useful.
Directional drilling operations are particularly enhanced by improved control. The ability to efficiently and reliably transmit commands from an operator to downhole drilling hardware may enhance the precision of the drilling operation. Downhole drilling hardware that, for example, deflects a portion of the drill string to steer the drilling tool is typically more effective when under tight control by an operator. The ability to continuously adjust the projected direction of the well path by sending commands to a steering tool may enable an operator to fine tune the projected well path based on substantially real-time survey and/or logging data. In such applications, both accuracy and timeliness of data transmission are clearly advantageous.
Prior art communication techniques that rely on the rotation rate of the drill string to encode data are known. For example U.S. Pat. No. 5,603,386 to Webster discloses a method in which the absolute rotation rate of the drill string is utilized to encode steering tool commands. U.S. Pat. No. 7,245,229 to Baron et al discloses a method in which a difference between first and second rotation rates is used to encode steering tool commands. U.S. Pat. No. 7,222,681 to Jones et al discloses a method in which steering tool commands and/or data may be encoded in a sequence of varying drill string rotation rates and drilling fluid flow rates. The varying rotation rates and flow rates are measured downhole and processed to decode the data and/or the commands.
While drill string rotation rate encoding techniques are commercially serviceable, there is room for improvement in certain downhole applications. For example, precise measurement of the drill string rotation rate can become problematic in deep and/or horizontal wells or when stick/slip conditions are encountered. Rotation rate encoding also commonly requires the drilling process to be interrupted and the drill bit to be lifted off bottom. Therefore, there exists a need for improved methods and systems for downlinking data and/or commands downhole.
The present invention addresses the need for an improved downlinking method and system for downhole tools. Aspects of the invention include a method for downlinking instructions from a surface location to a downhole tool such as a steering tool. A downlinking signal is transmitted downhole using drilling fluid as the communications medium. The downlinking signal includes at least a synchronization phase and a command phase. Attributes of the synchronization phase are used upon reception at the downhole tool to determine corresponding attributes of the command phase. For example, the synchronization phase may be configured to specify at least one of a bit length and a pulse level of the encoded command.
Exemplary embodiments of the present invention may advantageously provide several technical advantages. For example, the present invention advantageously enables the base flow rate, the pulse flow rate, and the bit length to be determined adaptively while drilling. The base flow rate may be selected, for example, for optimum drilling performance, while the pulse flow rate and the bit length may be selected on the fly based upon the signal condition (e.g., the bit length may be increased with increasing measured depth so as to improve the signal to noise ratio).
The present invention tends to be further advantageous in that the downlinking method does not require interruption of the drilling process. Commands may be transmitted downhole while drilling (i.e., while the drill bit is rotating on-bottom). Moreover, the present invention advantageously utilizes a distinct frequency channel as compared to conventional mud pulse telemetry and may therefore be simultaneously used with mud-pulse telemetry techniques (i.e., data may be transmitted downhole using the present invention at the same time data is being transmitted uphole using conventional mud pulse telemetry). These features of the invention can save considerable rig time.
In one aspect the present invention includes a method for transmitting a command from a surface location to a bottom hole assembly located in a borehole. The method includes pumping drilling fluid downhole through a drill string to the bottom hole assembly and changing a flow rate of the drilling fluid to encode a downlinking signal. The downlinking signal includes at least a synchronization phase and a command phase each of which includes at least one distinct pulse. The method further includes detecting the downlinking signal at the bottom hole assembly, decoding the synchronization phase to determine at least one of a bit length and a pulse level of the command phase, and decoding the command phase to determine the command based on the bit length and the pulse level determined from the synchronization phase.
In another aspect the present invention includes a system for communicating at least one command from a surface location to a bottom hole assembly located in a borehole. The system includes a pump for pumping drilling fluid from the surface through a drill string to the bottom hole assembly and a flow control apparatus for controlling a flow rate of the drilling fluid such that the flow rate encodes a downlinking signal. The downlinking signal includes at least a synchronization phase and a command phase each of which includes at least one distinct flow rate pulse. The system further includes a downhole detector configured to detect the downlinking signal and a downhole controller configured to decode the downlinking signal. The controller is configured to (i) decode the synchronization phase to determine at least one of a bit length and a pulse level of the command phase and (ii) decode the command phase to determine the command.
The foregoing has outlined rather broadly the features of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter which form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other methods, structures, and encoding schemes for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.
For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:
It will be understood by those of ordinary skill in the art that methods and apparatuses in accordance with this invention are not limited to use with a semisubmersible platform 12 as illustrated in
With continued reference to
An uphole controller 190 is configured to generate a signal, for example, a sequence of negative pressure (or fluid velocity) pulses in the drilling fluid. These pulses propagate downhole through the drilling fluid in the drill string and are received at downlinking detector 120. It will be appreciated that the signal may also be transmitted through the drilling fluid in the annulus. In one exemplary embodiment, the controller 190 may be in electronic communication with the pump 82. The signal (e.g., pressure or velocity pulses) may be generated, for example, via automatically changing the rotation speed of the pump (a negative pulse may be generated by momentarily reducing the rotation speed). The controller may also be in electronic communication with a sensor such as a pressure gauge or a flow meter. Such communication may provide a feedback mechanism for controlling the amplitude of the signal.
The controller may alternatively (and/or additionally) be in communication with a controllable valve 78 deployed in an optional bypass passageway 75. The bypass passageway 75 connects the standpipe 83 with the return 88 as depicted. Those of ordinary skill in the art will appreciate that opening (or partially opening) value 78 allows drilling fluid to flow through the bypass 75 (thereby bypassing the borehole), which in turn reduces the pressure (and/or flow rate) of the drilling fluid in the drill string.
Surface system 180 may further (or alternatively) include a commercially available rig controller, for example, a DrillLink® remote control interface available from National Oilwell Varco. In computer controlled systems, an operator may input a desired flow rate, for example via a suitable user interface such as a keyboard or a touch screen. In one advantageous embodiment, system 180 may include a computerized system in which an operator inputs the data and/or the command to be transmitted. For example, for a downhole steering tool, an operator may input desired tool face and offset values (as described in more detail below). The controller 190 then determines a suitable sequence of flow rate pulses and executes the sequence to transmit the data and/or commands to the tool 100.
While
As depicted on
Differential transducer 130 is disposed to measure a difference in pressure between drilling fluid in the drill string and drilling fluid in the borehole annulus (hydrostatic pressure). Bore 152 provides high pressure drilling fluid from the drill string to a first side 131 (or front side) of the differential transducer 130. Bores 147 and 148 provide hydraulic oil (at hydrostatic pressure) to a second side 132 (or back side) of the differential transducer 130. The transducer 130 measures a pressure difference between these fluids (between the front and back sides of the differential transducer).
A compensating piston 142 is deployed in and sealingly engages a second longitudinal bore 150 in pressure housing 122. The bore 150 and piston 142 define first and second oil filled and drilling fluid filled fluid chambers 144 and 146. Chamber 146 is in fluid communication with drilling fluid in the borehole annulus (at hydrostatic well bore pressure). It will be readily understood to those of ordinary skill in the art that the drilling fluid in the borehole exerts a force on the compensating piston 142 proportional to the hydrostatic pressure in the borehole, which in turn pressurizes the hydraulic fluid in chamber 144.
While the exemplary embodiment of downlinking detector 120 depicted on
It will further be understood that the drilling fluid velocity and the drilling fluid pressure (or differential pressure) are closely related quantities (they are essentially directly proportional to one another in the sub 1 Hertz frequency range of interest). Therefore measurement of one of these quantities is generally indicative of the other (e.g., a measurement of drilling fluid pressure is generally indicative of drilling fluid velocity and visa-versa). Likewise, the control of one these quantities at the surface tends also to control the other (e.g., control of drilling fluid velocity tends also to control drilling fluid pressure or differential pressure). As a result, certain embodiments of the invention may include controlling one parameter at the surface (e.g., velocity) and measuring the other downhole (e.g., differential pressure).
Those of skill in the art will further appreciate that downlinking detector 120 may further be utilized as a drill string or annular pressure while drilling measurement tool. For example, the differential pressure (measured via differential transducer 130) may be summed with an annular pressure measurement to obtain the pressure in the drill string. Likewise, the differential pressure may be subtracted from a drill string pressure measurement to obtain the annular pressure.
Turning now to
When the drilling fluid pumps are turned off (e.g., when a new section of drill pipe is attached to the drill string) the differential transducer indicates a zero level (in analog to digital raw counts). This value is stored as a zero pressure reference level. In exemplary embodiments of the invention, the zero level may be accurately sampled at periodic intervals during drilling. After turning on the mud pumps at 202, a full flow rate level may be established when the flow rate stabilizes (e.g., after a predetermined period such as 30 seconds). A negative pulse value (or threshold) may be computed from the base and zero levels, for example as follows:
PT=Base−R·(Base−Zero) Equation 1
where PT represents the pulse threshold in ADC counts, Base represents the base level counts, Zero represents the zero level counts, and R represents a predetermined flow reduction rate for a negative pressure pulse (e.g., a pressure pulse having a 15, 20, or 25% reduction in flow rate from the base level).
The command phase 214 includes the encoded command (or data). In the exemplary embodiment depicted, the command phase is divided into eight bits (a single start bit and a seven-bit command). It will be understood that the invention is not limited to any particular number of command bits. The bit length Tbit may be computed, for example, from Tsync (or alternatively from Tlow and/or Thigh). In the exemplary embodiment depicted, Tbit is arbitrarily defined as follows: Tbit=Tsync÷5 . The use of the synchronization phase 212 advantageously enables Tbit to be selected based on drilling conditions (e.g., it is often desirable to increase Tbit with increasing measured depth of the borehole). Suitable bit lengths are commonly in the range from about 5 to about 30 seconds. The binary value (0 or 1) of each bit may be determined from the measured pressure (or flow rate) during Tbit as indicated. In the exemplary embodiment depicted, a value of ‘0’ is assigned to the base level and a value of ‘1’ is assigned to the negative pressure pulse (e.g., a value within a predetermined range of the pressure threshold defined above with respect to Equation 1).
While the invention is not limited to any particular bit length, it will be understood that bit lengths in the range from about 5 to about 30 seconds tend to be advantageous for several reasons. For example, the use of a longer bit length tends to advantageously improve communication accuracy in deeps wells or when downlinking while drilling. Moreover, the use of bit lengths in the above range advantageous enables simultaneous downlinking and uplinking at different frequencies.
With continued reference to
In the exemplary embodiments depicted on
It will be understood that the invention is in no way limited to embodiments in which the command phase includes a seven-bit command. Substantially any bit length may be utilized. For example, a four or five-bit command may be readily utilized for operations in which a well having a relatively simple profile is drilled (e.g., conventional J-shaped or S-shaped wells). These commands may include for example, the differential and specialized commands described above.
As is known to those of ordinary skill in the art, rotary steerable tools (such as steering tool 50 in
In preferred embodiments of the invention, the most frequently utilized commands (e.g., wake-up, blade collapse, and the like) may be advantageously configured to have the fewest number of fluid pressure or velocity changes (e.g., via valve actuations). When using an eight bit command phase, a rotary steerable wake-up command may given, for example, by the hexadecimal FF (binary 11111111), which requires no valve actuations in the command phase. A rotary steerable blade collapse command may be given, for example, by the hexadecimal F0 (binary 11110000), which requires only a single actuation in the command phase. Other commonly utilized commands may be programmed, for example, using hexadecimal F8, FC, FE, 80, C0, and E0, each of which requires only a single actuation in the command phase. The invention is, of course, not limited in this regard. Minimizing valve and/or pump actuation tends to advantageously also minimize wear to the surface system components (e.g., valve 78 on
It will be further understood that the invention is not limited to embodiments in which only steering tool commands are downlinked. Those of ordinary skill in the art will readily appreciate that commands may also be downlinked to substantially any downhole tool, for example, including MWD tools, LWD tools, underreamers, packers, fluid sampling devices and the like. For example, downlinking detector 120 (
Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the invention as defined by the appended claims.
