Managing rotational information on a drill string

• US 10,273,756 B2
• Filed: 09/15/2014
• Issued: 04/30/2019
• Est. Priority Date: 09/15/2014
• Status: Active Grant

• Current Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Original Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Inventors: Wong, David Yan Lap
• Primary Examiner(s): Bagnell, David J
• Assistant Examiner(s): Schimpf, Tara E
• Application Number:
  US14/485,905
• Publication Number:
  US 20160076361A1
• Time in Patent Office: 1,688 Days
• 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: E21B 7/06 Deflecting the direction of boreholes
• CPC Class Codes: E21B 7/062 the tool shaft rotating inside a non-rotating guide travelling with the shaft E21B7/067 and E21B7/068 take precedence
• CPC Class Codes: E21B 7/067 with means for locking sections of a pipe or of a guide for a shaft in angular relation, e.g. adjustable bent sub
• CPC Class Codes: E21B 7/068 drilled by a down-hole drilling motor down-hole drives per se E21B4/00, E21B7/067 takes precedence

Abstract

A method for sharing information between components of a subterranean drill string. The method can include receiving, at a controller, data representative of a detected rotational characteristic of a drill string sensed at a first location on the drill string. Further, the method includes calculating, at the controller, a rotational characteristic corresponding to a second location on the drill string based, at least in part, on the detected data, and transmitting data representative of the calculated rotational characteristic to the second location.

Claims

1. A method comprising:

receiving, at a controller, data representative of a first detected rotational characteristic of a drill string sensed at a first downhole location on the drill string;

calculating, at the controller, a second rotational characteristic corresponding to a second downhole location on the drill string based, at least in part, on the received data;

transmitting data representative of the calculated second rotational characteristic to a tool at the second downhole location,

receiving, by the tool, the data representative of the calculated second rotational characteristic, and

operating the tool at the second downhole location utilizing the received calculated second rotational characteristic corresponding to the second downhole location.

2. The method of claim 1, wherein:

calculating the second rotational characteristic comprises estimating an approximate rotational characteristic corresponding to the tool on the drill string based, at least in part, on the received data.

3. The method of claim 2, wherein estimating the approximate corresponding rotational characteristic for the tool on the drill string comprises estimating an approximate corresponding rotational characteristic for the entire drill string.

4. The method of claim 1, further comprising:

outputting, at the controller, data representative of the corresponding second rotational characteristic to the tool at the second downhole location on the drill string.

5. The method of claim 4, wherein

receiving, at the controller, data representative of the detected first rotational characteristic of a drill string sensed at the first downhole location on the drill comprises receiving, at the controller, data representative of the detected first rotational characteristic of the drill string sensed at a plurality of downhole locations, including the first downhole location, on the drill string.

6. The method of claim 4, further comprising:

receiving at the tool at the second downhole location the outputted data on a communication channel and broadcasting the received data along the drill string on the communication channel for utilization at a plurality of downhole locations on the drill string, including the second downhole location.

7. The method of claim 6, wherein the communication channel is a communication bus extending along a length of the drill string and communicatively interconnecting a plurality of constituent tools of the drill string.

8. The method of claim 4, wherein the detected first rotational characteristic of the drill string sensed at the first downhole location on the drill string is revolution speed and the corresponding second rotational characteristic transmitted to the tools at the second downhole location on the drill string is a revolution speed value calculated from the detected revolution speed at the first downhole location.

9. The method of claim 8, wherein the revolution speed value at the tool at the second downhole location is calculated based on an estimated approximation using the detected revolution speed at the first downhole location.

10. The method of claim 9, wherein the estimated approximation is based on a linear extrapolation.

11. The method of claim 9, wherein the approximation is based on a curve which substantially fits a plurality of detected revolution speeds along the drill string, the plurality of detected revolution speeds including at least the detected revolution speed a the first downhole location.

12. The method of claim 9, wherein the approximation is based, at least in part, on the detected revolution speed at the first downhole location taken dynamically over time.

13. The method of claim 9 further comprising:

receiving, at the controller, data representative of detected revolution speeds of the drill string sensed at a plurality of downhole locations, including the first downhole location; and

calculating, at the controller, a revolution speed value in dependence on the data representative of the detected revolution speeds sensed at the plurality of downhole locations for utilization at a plurality of downhole locations on the drill string, including the tool at the second downhole location.

14. The method of claim 13, wherein the calculation of the revolution speed value comprises averaging the detected revolution speeds sensed at the plurality of downhole locations and the result is the calculated revolution speed value.

15. The method of claim 4, wherein the corresponding rotational characteristic is an acceleration value calculated from a detected revolution speed.

16. The method of claim 15, determining the occurrence of drill string stick-slip conditions from analysis of acceleration values.

17. The method of claim 4, further comprising:

receiving the outputted data representative of the corresponding rotational characteristic value by the tool at the second downhole location, wherein the tool at the second downhole location is operationally dependent upon the received data representative of the corresponding rotational characteristic value.

18. The method of claim 17, further comprising:

generating the data received at the controller that is representative of the rotational characteristic of the drill string at the first downhole location on the drill string with a sensor positioned at the first downhole location on the drill string.

19. The method of claim 18, further comprising:

determining that the sensor that detects rotational characteristics of the drill string at the second tool is inoperative; and

utilizing the output data representative of the corresponding rotational characteristic value by the tool at the second downhole location.

20. The method of claim 17, wherein the tool at the second downhole location is a rotary steerable subterranean drill.

21. The method of claim 17, wherein the tool at the second downhole location is a drilling shaft deflection device of a rotary steerable subterranean drill.

22. A drilling system comprising:

a subterranean drill string;

a plurality of rotational characteristic sensors arranged on the drill string;

a drill string communication system; and

a controller, located at a first downhole location;

wherein the controller receives data representative of a detected first rotational characteristic of the drill string sensed by one of the plurality of rotational characteristic sensors at the first downhole location on the drill string,

the controller calculates a second rotational characteristic corresponding to a second downhole location on the drill string, based, at least in part, on the detected data; and

data representative of the calculated second rotational characteristic is received by a tool at the second downhole location, the received calculated second rotational characteristic used to operate the tool at the second downhole location.

23. The drilling system of claim 22, wherein the calculated second rotational characteristic is received by the tool at the second downhole location, wherein the tool at the second downhole location is operationally dependent upon the received data representative of the corresponding rotational characteristic value.

24. The drilling system of claim 23, wherein the tool at the second downhole location is a rotary steerable subterranean drill.

25. The drilling system of claim 24, wherein the tool at the second downhole location is a drilling shaft deflection device of a rotary steerable subterranean drill.

26. The drilling system of claim 25, wherein the drilling shaft deflection device further comprises:

a drilling shaft rotatably supported in a housing;

a drilling shaft deflection assembly comprising an outer eccentric ring and an inner eccentric ring that engages the drilling shaft; and

a pair of drive motors anchored relative the housing and respectively coupled, one each, to the inner and outer eccentric rings for independently rotating each eccentric ring in either rotational direction.

27. The drilling system of claim 26, wherein the drilling shaft deflection device further comprises:

the housing being generally cylindrical and having a longitudinal centerline, the longitudinal centerlines of the drilling shaft and housing being substantially coincident when the drilling shaft is undeflected within the housing;

the drilling shaft deflection assembly contained within the housing;

the outer eccentric ring being rotatably supported at an inner peripheral surface of the housing and having a circular inner peripheral surface that is eccentric with respect to the housing;

the inner eccentric ring being rotatably supported at the circular inner peripheral surface of the outer eccentric ring and having a circular inner peripheral surface that engages the drilling shaft and which is eccentric with respect to the circular inner peripheral surface of the outer eccentric ring; and

one of the pair of motors drivingly coupled by a first transmission to the outer eccentric ring and which rotates the outer eccentric ring in a first direction and an opposite, second direction relative to the housing and the other of the pair of motors drivingly coupled by a second transmission to the inner eccentric ring and which rotates the inner eccentric ring relative to the outer eccentric ring.

28. A method for sharing information between components of a subterranean drill string, the method comprising:

receiving, at a downhole controller, data representative of a detected first characteristic of a drill string;

sensed at a first downhole location on the drill string; and

calculating, at the controller, a corresponding second characteristic in dependence upon the received data representative of the detected first characteristic of the drill string sensed at the first downhole location on the drill string for utilization at a tool located at another downhole location than the first location on the drill string; and

operating the tool using the second characteristic.

29. The method of claim 28, wherein the detected characteristic is chosen from the group comprising:

(i) a rotational characteristic;

(ii) a pressure characteristic; and

(iii) a temperature characteristic.