# US 8,570,833 B2 · Downlinking communication system and method > Agents: this data is available as JSON from the patentgrep API and MCP server — see https://patentgrep.com/llms.txt - Number: US 8,570,833 B2 - Document ID: US8570833B2 - Status: Granted - Kind: B2 - Application number: 12/785,995 - Filed: 2010-05-24 - Published: 2011-11-24 - Granted: 2013-10-29 - Earliest claimed: 2010-05-24 - Assignees: Schlumberger Technology Corporation - Applicants: Junichi Sugiura - Inventors: Junichi Sugiura - Web page: https://patentgrep.com/patent/US8570833B2 ## CPC - E21B 47/22: by negative mud pulses using a pressure relieve valve between drill pipe and annulus - E21B 47/017: Protecting measuring instruments - E21B: EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS ## Abstract A downlinking signal is transmitted downhole from the surface 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 of the signal to determine corresponding attributes of the command phase. Commands may be transmitted downhole while drilling and simultaneously while using mud-pulse telemetry uplinking techniques. ## Claims ### Claim 1 A method for transmitting a command from a surface location to a bottom hole assembly located in a borehole, the method comprising: (a) pumping drilling fluid downhole through a drill string to the bottom hole assembly; (b) changing a flow rate of the drilling fluid to encode a downlinking signal, the downlinking signal including at least a synchronization phase and a command phase, each of the synchronization phase and the command phase including at least one distinct pulse; (c) detecting the downlinking signal at the bottom hole assembly; (d) decoding the synchronization phase to determine at least one of a bit length and a pulse level of the command phase; and (e) decoding the command phase to determine the command based on the bit length and the pulse level determined in (d). ### Claim 2 (depends on 1) The method of claim 1, wherein the synchronization phase and the command phase each include at least one distinct negative flow rate pulse. ### Claim 3 (depends on 1) The method of claim 1, wherein the synchronization phase includes a negative pulse during a first time period and a return to a base level during a second time period. ### Claim 4 (depends on 1) The method of claim 1, wherein the synchronization phase includes a negative pressure pulse, a level of the negative pressure pulse determining the pulse level of the command phase. ### Claim 5 (depends on 1) The method of claim 1, wherein the bit length is computed from a pulse width of the at least one pulse in the synchronization phase. ### Claim 6 (depends on 1) The method of claim 1, wherein the command phase comprises at least first and second distinct commands, each of the commands including at least four bits. ### Claim 7 (depends on 1) The method of claim 1, wherein the downlinking signal further comprises an assertion phase, the assertion phase indicating the end of the downlinking signal and including a base level signal for a time period of at least twice the bit length of the command phase. ### Claim 8 (depends on 1) The method of claim 1, wherein the bottom hole assembly comprises a rotary steerable tool configured to execute the command, the rotary steerable tool including a plurality of extendable and retractable blades, the blades being operative to control a direction of drilling of the borehole, the method further comprising: (f) executing the command, said execution of the command causing extension or retraction of at least one of the blades. ### Claim 9 (depends on 8) The method of claim 8, wherein the command is selected from the group consisting of absolute offset, absolute percentage force, absolute toolface angle, absolute target inclination, absolute target azimuth, absolute dogleg severity, change in offset, change in percentage force, change in toolface angle, change in inclination, change in azimuth, and change in dogleg severity. ### Claim 10 (depends on 1) The method of claim 1, wherein (a) further comprises rotary drilling the borehole. ### Claim 11 (depends on 1) The method of claim 1, wherein the flow rate is changed in (b) via actuating a bypass valve. ### Claim 12 (depends on 1) The method of claim 1, wherein the flow rate is changed in (b) via changing the rotation speed of a pump. ### Claim 13 (depends on 1) The method of claim 1, wherein the downlinking signal is detected using a differential pressure transducer configured to measured a pressure differential between drilling fluid in the drill string and drilling fluid in a borehole annulus. ### Claim 14 A system for communicating at least one command from a surface location to a bottom hole assembly located in a borehole, the system comprising: a pump for pumping drilling fluid from the surface through a drill string to the bottom hole assembly; a flow control apparatus for controlling a flow rate of the drilling fluid, the flow rate encoding a downlinking signal, the downlinking signal including at least a synchronization phase and a command phase, each of the synchronization phase and the command phase including at least one distinct flow rate pulse; a downhole detector configured to detect the downlinking signal; and a downhole controlled configured to decode the downlinking signal, the controller 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. ### Claim 15 (depends on 14) The system of claim 14, wherein the flow control apparatus is computer controlled. ### Claim 16 (depends on 14) The system of claim 14, wherein the flow control apparatus is configured to selectively open and close a bypass valve, wherein opening the bypass valve reduces the flow rate in the drill string. ### Claim 17 (depends on 14) The system of claim 14, wherein the flow control apparatus is configured to control the rotation rate of the pump. ### Claim 18 (depends on 14) The system of claim 14, wherein the detector comprises a differential transducer configured to measure a pressure differential between drilling fluid in the drill string and drilling fluid in a borehole annulus. ### Claim 19 (depends on 14) The system of claim 14, wherein the controller is configured to compute the bit length from a pulse width of a predetermined pulse in the synchronization phase. ### Claim 20 (depends on 14) The system of claim 14, wherein the controller is configured to determine the pulse level of the command phase from a pulse width of a predetermined pulse in the synchronization phase. ### Claim 21 (depends on 14) The system of claim 14, further comprising a rotary steerable tool configured to execute the command, the rotary steerable tool including a plurality of extendable and retractable blades, the blades being operative to control a direction of drilling of the borehole, execution of the command causing extension or retraction of at least one of the blades, the command being selected from the group consisting of absolute offset, absolute percentage force, absolute toolface angle, absolute target inclination, absolute target azimuth, absolute dogleg severity, change in offset, change in percentage force, change in toolface angle, change in inclination, change in azimuth, and change in dogleg severity.