Drill string rotation encoding

• US 7,245,229 B2
• Filed: 07/01/2004
• Issued: 07/17/2007
• Est. Priority Date: 07/01/2003
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Original Assignee: Pathfinder Energy Services LLC (Schlumberger NV)
• Inventors: Jones, Stephen, Baron, Emilio
• Primary Examiner(s): WONG, ALBERT KANG
• Application Number:
  US10/882,789
• Publication Number:
  US 20050001737A1
• Time in Patent Office: 1,111 Days
• Field of Search: 367/82, 340/853.1, 340/853.4, 340/853.3, 175/38, 175/76, 175/57, 702/9
• US Class Current: 340/853.3
• CPC Class Codes: E21B 47/12 Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
• CPC Class Codes: G01V 11/002 Details, e.g. power supply systems for logging instruments, transmitting or recording data, specially adapted for well logging, also if the prospecting method is irrelevant means for transmitting well survey signals E21B47/12; signal transmission systems in general G08C; transmission in general H04B

Abstract

A method for communicating with a downhole device is provided. The method includes predefining an encoding language including codes understandable to the device, the codes represented in the language as predefined value combinations of drill string rotation variables such as rotation rate or duration. The method further includes rotating a drill string at first and second rates and measuring the rotation rates downhole. The first measured rotation rate is processed downhole in combination with the second measured rotation rate to acquire a code in the language at the downhole device. Embodiments of the invention are useful, for example, for transmitting commands from the surface to a downhole device such as a directional drilling tool. Exemplary embodiments of this invention advantageously provide for quick and accurate communication with a downhole device without substantially interrupting the drilling process.

Claims

1. A method for communicating with a downhole device deployed in a subterranean borehole, the method comprising:

(a) deploying a downhole device in a subterranean borehole, the device being coupled to a drill string, the drill string being rotatable about a longitudinal axis, the device including a measurement device operative to measure rotation rates of the drill string about the longitudinal axis;

(b) predefining an encoding language comprising codes understandable to the downhole device, the codes represented in said language as predefined value combinations of drill string rotation variables, said variables including a difference between first and second rotation rates;

(c) causing the drill string to rotate at substantially a preselected first rotation rate;

(d) causing the drill string to rotate at substantially a preselected second rotation rate;

(e) causing the measurement device to measure the first and second rotation rates; and

(f) processing downhole the difference between the first and second rotation rates measured in (e) to determine if one of said variables is received and acquiring at least one code from the variable at the downhole device, wherein the difference is not based on a preselected base rotation rate.

2. The method of claim 1, wherein the first and second rotation rates are each within predefined ranges of rotation rates, and wherein all rotation rates within said ranges are operable to enable physical drilling of the borehole.

3. The method of claim 1, wherein the downhole device comprises a directional drilling tool.

4. The method of claim 3, wherein:

the directional drilling tool comprises extendable blades, the blades being operative to control a direction of drilling of the subterranean borehole; and

the at least one code comprises at least one command, the command causing the directional drilling tool to extend at least one blade to a pre-desired position.

5. The method of claim 1, wherein the downhole device comprises a substantially non-rotating housing.

6. The method of claim 5, wherein the measurement device includes a marker deployed on the drill string and a sensor deployed on the substantially non-rotating housing, the sensor disposed to detect the marker as it rotates by the sensor.

7. The method of claim 1, wherein the drill string rotation variables in (b) further include duration.

8. The method of claim 7, wherein (c) comprises rotating the drill string within a predefined range about the first rotation rate for a predetermined duration to establish a non-zero base rotation rate, and wherein the predefined value combinations of drill string rotation variables in (b) include the base rotation rate.

9. The method of claim 7, wherein (c) and (d) further comprise rotating the drill string within predefined ranges about the first and second rotation rates for corresponding first and second predetermined durations, and wherein (e) further includes measuring said durations.

10. The method of claim 9, wherein (f) further comprises processing the durations measured in (e) to acquire the at least one code in said language at the downhole device.

11. The method of claim 1, wherein the codes comprise commands, the commands operative to trigger predetermined responses in the downhole device.

12. The method of claim 11, wherein the downhole device executes the commands upon receipt thereof.

13. The method of claim 1, wherein (d) further comprises causing the drill string to rotate through a predefined sequence varying rotation rates, the sequence including the second rotation rate, the drill string rotation variables in (b) including at least one member of the group consisting of (i) a rotation rate at a predetermined time in the sequence and (ii) a duration of rotation during a predetermined portion of the sequence.

14. The method of claim 13, wherein the sequence comprises at least one pulse, the pulse including (i) a first transition in which the rotation rate changes from substantially the first rotation rate to substantially the second rotation rate and (ii) a plateau in which the rotation rate is within a predefined range of the second rotation rate for substantially a predetermined pulse duration.

15. The method of claim 14, wherein the pulse further comprises (iii) a second transition in which the rotation rate changes from substantially the second rotation rate to substantially the first rotation rate.

16. The method of claim 14, wherein:

(e) further comprises measuring the pulse duration, and

(f) comprises processing the pulse duration measured in (e) to acquire the at least one code in said language at the downhole device, the drill string rotation variables in (b) including the pulse duration.

17. The method of claim 1, wherein the first and second rotation rates are measured in (e) by timing a rotation of the drill string.

18. The method of claim 1, further comprising:

(g) receiving, at the surface, sensor data acquired by a sensor deployed in the subterranean borehole.

19. The method of claim 18, further comprising:

(h) responsive to the sensor data received at the surface in (g), receiving further codes in said language at the downhole device via further communication of predefined value combinations of drill string rotation variables.

20. A method for communicating with a downhole device deployed in a subterranean borehole, the method comprising:

(a) deploying a downhole device in a subterranean borehole, the device being coupled to a drill string, the drill string being rotatable about a longitudinal axis, the device including a measurement device operative to measure rotation rates of the drill string about the longitudinal axis;

(b) predefining an encoding language comprising codes understandable to the downhole device, the codes represented in said language as predefined value combinations of drill string rotation variables, said variables including a difference between a first preselected rotation rate and a second preselected rotation rate and a duration;

(c) causing the drill string to rotate at substantially a predefined first rotation rate for substantially a first predetermined duration;

(d) causing the drill string to rotate at substantially a predefined second rotation rate for substantially a second predetermined duration;

(e) causing the measurement device to measure the first and second rotation rates and the first and second durations; and

(f) processing downhole (i) the difference between the first and second rotation rates measured in (e) and (ii) at least one of the first and second durations measured in (e) to determine if one of said variables is received and acquiring acquire at least one code in said language at the downhole device, wherein the difference is not based on a preselected base rotation rate.

21. The method of claim 20, wherein the first and second rotation rates are within predefined ranges of rotation rates, wherein all rotation rates within said predefined ranges are operable to enable physical drilling of the borehole.

22. The method of claim 20, wherein:

the downhole device further comprises a directional drilling tool, the directional drilling tool including extendable blades, the blades being operative to control a direction of drilling of the subterranean borehole; and

the at least one code comprises at least one command, the command causing the directional drilling tool to extend at least one blade to a pre-desired position.

23. The method of claim 20, wherein:

the downhole device comprises a substantially non-rotating tool housing; and

the measurement device includes a marker deployed on the drill string and a sensor deployed on the tool housing, the sensor disposed to detect the marker as it rotates by the sensor.

24. The method of claim 20, wherein (d) further comprises causing the drill string to rotate through a predefined sequence of varying rotation rates, the sequence including the second rotation rate.

25. The method of claim 24, wherein the sequence comprises at least one pulse, the pulse including (i) a first transition in which the rotation rare changes from substantially the first rotation rate to substantially the second rotation rate and (ii) a plateau in which the rotation rate is within a predefined range of the second rotation rate for substantially the second predetermined duration.

26. The method of claim 25, wherein the pulse further comprises (iii) a second transition in which the rotation rate changes from substantially the second rotation rate to substantially the first rotation rate.

27. A method for communicating with a downhole device deployed in a subterranean borehole, the method comprising:

(a) deploying a downhole device in a subterranean borehole, the device being coupled to a drill string, the drill string being rotatable about a longitudinal axis, the device including a measurement device operative to measure a rotation rate of the drill string about the longitudinal axis;

(b) predefining an encoding language comprising codes understandable to the downhole device, the codes represented in said language as predefined value combinations of drill string rotation variables, said variables including (i) a first rotation rate, (ii) first and second durations, and (iii) a difference between a second rotation rate and a base rotation rate;

(c) causing the drill string to rotate at substantially the first rotation rate for substantially the first duration;

(d) causing the drill string to rotate at substantially the second rotation rate for substantially the second duration;

(e) causing the measurement device to measure the first and second rotation rates and the first and second durations;

(f) processing the first rotation rate and the first duration to establish the base rotation rate; and

(g) processing downhole (i) the difference between the second rotation rate measured in (e) and the base rotation rate established in (f) and (ii) the second duration measured in (e) to determine if one of said variables is received and acquiring at least one code from the variable at the downhole device, wherein the difference is not based on a preselected base rotation rate.

28. The method of claim 27, wherein:

the downhole device comprises a directional drilling tool, the directional drilling tool including extendable blades, the blades being operative to control a direction of drilling of the subterranean borehole; and

the code comprises at least one command, the command causing the directional drilling tool to extend at least one blade to a pre-desired position.

29. The method of claim 27, wherein:

the downhole device comprises a substantially non-rotating tool housing; and

the measurement device includes a marker deployed on the drill string and a sensor deployed on the tool housing, the sensor disposed to detect the marker as it rotates by the sensor.

30. The method of claim 27, wherein (d) farther comprises causing the drill string to rotate through a predefined sequence of varying rotation rates, the sequence comprising at least one pulse, the pulse including (i) a first transition in which the rotation rate changes from substantially the base rotation rate to substantially the second rotation rate and (ii) a plateau in which the rotation rate is within a predefined range of the second rotation rate for substantially a predetermined pulse duration.

31. The method of claim 30, wherein the pulse further comprises (iii) a second transition in which the rotation rate changes from substantially the second rotation rate to substantially the base rotation rate.

32. A method for transmitting commands from a drilling rig to a downhole device deployed in a subterranean borehole, the method comprising:

(a) deploying a downhole device in a subterranean borehole, the device being coupled to a drill string, the drill string being rotatable about a longitudinal axis, the device including a measurement device operative to measure a rotation rate of the drill string about the longitudinal axis;

(b) predefining an encoding language comprising commands understandable to the downhole device, the commands represented in said language as predefined value combinations of drill string rotation variables, said variables including a difference between a pulse rotation rate and a base rotation rate and a pulse duration;

(c) establishing a base rotation rate by causing the drill string to rotate at substantially the first rotation rate for substantially a first predetermined duration;

(d) causing the drill string to rotate through a predefined sequence of varying rotation rates, the predefined sequence including a plurality of drill string rotation pulses, each of the pulses including (i) a first transition in which a rotation rate of the drill string transitions from substantially the base rotation rate to substantially the pulse rotation rate, (ii) a plateau in which the rotation rate of the drill string remains within a predefined range of the pulse rotation rate for substantially the pulse duration, and (iii) a second transition in which the rotation rate of the drill string transitions from substantially the pulse rotation rate to substantially the base rotation rate;

(e) measuring downhole (i) the base rotation rate, (ii) the pulse rotation rate of each pulse, and (iii) the pulse duration of each pulse; and

(f) processing downhole the difference between each of the pulse rotation rates measured in (e) and the base rotation rate measured in (3) and (ii) the pulse durations measured in (e) to determine if one of said variables is received and acquiring at least one command from the variable at the downhole device, wherein the difference is not based on a preselected base rotation rate.

33. In a downhole telemetry system in which drill string rotation variables are used to encode communication with a downhole device coupled to a drill string, an improved method for receiving at least one predefined code at the downhole device via a sequence of encoded drill string rotation variables, the improvements comprising:

(a) causing the drill string to rotate at first and second rotation rates;

(b) causing the downhole device to measure the first and second rotation rates; and

(c) calculating downhole a difference between the first and second rotation rates measured in (b) to determine if one of said variables is received and acquiring at least one code from the variable at the downhole device, wherein the difference is not based on a preselected base rotation rate.

34. A method for encoding a command transmitted from a drilling rig to a downhole steering tool deployed in a subterranean borehole, the method comprising:

(a) deploying the steering tool in the borehole, the steering tool being coupled to a drill string, the drill string rotatable about a longitudinal axis thereof, the steering tool further including a measurement device operative to measure a rotation rate of the drill string about the longitudinal axis;

(b) predefining an encoding language comprising commands understandable to the steering tool, the commands operative, when received by the steering tool, to trigger a predetermined response in the steering tool, the commands represented in said language and understandable by the steering tool as predefined value combinations of drill string rotation variables, said variables including (i) a difference between a second rotation rate and a base rotation rate and (ii) a pulse duration;

(c) establishing a base rotation rate by causing the drill string to rotate within a predefined range for substantially a first predetermined duration, wherein the base rotation rate is not predefined;

(d) commanding the steering tool by causing the drill string to rotate through a predefined sequence of value combinations of drill string rotation variables, the predefined sequence including value combinations of drill string rotation variables understandable by the steering tool as commands, the predefined sequence including at least one drill string rotation pulse in which the drill string rotates at the second rotation rate for the pulse duration.

35. The method of claim 34, wherein the base rotation rate and all rotation rates included in the predefined sequence are operable to enable physical drilling of the borehole.

36. The method of claim 34, wherein causing the drill string to rotate through a predefined sequence of value combinations of drill string rotation variables in (d) is accomplished manually.

37. The method of claim 34, wherein causing the drill string to rotate through a predefined sequence of value combinations of drill string rotation variables in (d) is computer-assisted.

38. A method for decoding a command at a downhole steering tool deployed in a subterranean borehole, the command represented as a unique value combination of drill string rotation variables in a predefined encoding language, the command operative to trigger a predetermined response in the steering tool, the method comprising:

(a) deploying the steering tool in the borehole, the steering tool including a rotatable shaft deployed in a substantially non rotating body, the non rotating body including at least one blade operative to deflect the steering tool in the borehole, the rotatable shaft being coupled to a drill string, the drill string rotatable about a longitudinal axis thereof, the steering tool further including a measurement device operative to measure a rotation rate of the drill string about the longitudinal axis;

(b) causing the measurement device to measure a rotation rate;

(c) assigning the rotation rate measured in (b) to a base rotation rate parameter upon satisfying a predetermined program condition;

(d) causing the tool to measure a plurality of parameters of a predefined code sequence of varying rotation rates, the plurality of parameters including (i) a rotation rate at a predetermined time in the code sequence and (ii) a duration of a predetermined portion of the code sequence;

(e) assigning (i) a difference between the rotation rate measured in (d) and the base rotation rate parameter assigned in (c) to a first measurement parameter and (ii) the duration measured in (d) to a second measurement parameter;

(f) determining the command in said language at the steering tool by processing downhole the first and second measurement parameters assigned in (e) to determine if one of said variables is received and acquiring at least one code from the variable at the downhole device, wherein the difference is not based on a preselected base rotation rate.

39. The method of claim 38, wherein the steering tool executes the command upon receipt.

40. The method of claim 38, wherein the measurement device includes a marker deployed on the drill string and a sensor deployed on the substantially non-rotating housing, the sensor disposed to detect the marker as it rotates by the sensor.

41. A system for decoding a command transmitted downhole to a downhole device, the command encoded via rotation of a drill string to which the downhole device is coupled, the command encoded as a predetermined value combination of drill string rotation variables, said variables including a difference between a first and second drill string rotation rates, the system comprising:

a measurement device deployed on the downhole device, the measurement device operative to measure rotation rates of the drill string and to send said measured rotation rates to a downhole controller;

the controller pre-programmed to give predefined command signals to the downhole device upon recognition of corresponding predefined value combinations of said drill string rotation variables;

the controller configured to;

(A) receive a first measured rotation rate of the drill string from the measuring device;

(B) receive a second measured rotation rate of the drill string from the measuring device;

(C) calculate the difference between the first measured rotation rate received in (A) and the second measured rotation rate received in (B) to identify a corresponding command signal; and

(D) send said command signal to the downhole device.

42. The system of claim 41, wherein the drill string rotation variables further comprise duration, and wherein the controller is further configured to:

received from the measuring device (i) a first measured duration in (A) during which the drill string rotates at substantially the first measured rotation rate and (ii) a second measured duration in (B) during which the drill string rotates at substantially the second measured rotation rate; and

process in (C) the second measured duration in combination with the difference between the first and second measured rotation rates to identify a corresponding command signal.

43. A computer-readable medium storing computer executable logic understandable by a downhole processor to enable the processor to perform a method for decoding a command transmitted downhole to a downhole device, the command encoded via rotation of a drill string to which the downhole device is coupled, the command encoded as a predetermined value combination of drill string rotation variables, said variables including a difference between first and second drill string rotation rates, the method comprising:

(a) receiving a first measured rotation rate of the drill string from a measuring device deployed on the downhole device;

(b) receiving a second measured rotation rate of the drill string from the measuring device;

(c) calculating the difference between the first measured rotation rate received in (a) and the second measured rotation rate received in (b) to identify a command signal via reference to a pre-programmed set of command signals corresponding to predefined value combinations of said drill string rotation variables; and

(d) sending said command signal to the downhole device.

44. The computer-readable medium of claim 43, wherein the drill string rotation variables further comprise duration, and wherein:

(a) further comprises receiving a first measured duration during which the drill string rotates at substantially the first measured rotation rate;

(b) further comprises receiving a second measured duration in during which the drill string rotates at substantially the second measured rotation rate; and

(c) further comprises processing the second measured duration first measured rotation rate and the first measured duration in combination with the difference between the first and second measured rotation rates in order to identify the command signal.