Drilling wellbores with optimal physical drill string conditions

• US 20050279532A1
• Filed: 06/22/2004
• Published: 12/22/2005
• Est. Priority Date: 06/22/2004
• Status: Active Grant

• Current Assignee: Baker Hughes Incorporated (Baker Hughes Company)
• Original Assignee: Baker Hughes Incorporated (Baker Hughes Company)
• Inventors: Neubert, Michael, Mathiszik, Holger, Ballantyne, Ray
• Granted Patent: US 7,730,967 B2
• Time in Patent Office: Days
• US Class Current: 175/40
• 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 49/00 Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
• CPC Class Codes: G01V 1/42 using generators in one well and receivers elsewhere or vice versa G01V1/52 takes precedence

Abstract

A drilling system includes a control unit and a bottomhole assembly (BHA) coupled to a drill string. The control unit uses measurements from sensors distributed throughout the drill string and BHA to determine the physical condition of the drill string and BHA and to determine whether drilling can be optimized. The drill string sensors are housed in receiver subs and optionally can be positioned on extensible members. The receiver sub also can include a short-hop telemetry module, a processor module, and a clock module. In one embodiment, the receiver subs include seismic sensors for enabling vertical seismic profiling. During operation, the processor visually presents to the operator via one or more graphical user interfaces a dynamically updated pictorial image representing the drilling system. The image is annotated with an appropriate visual signal to indicate a determined physical condition at a given location or component. The processor can also display recommended adjustments to drilling parameters for increasing drilling rates, improving tool life, and more precise steering.

Claims

1. A method of controlling the drilling of a wellbore using a drill string formed of jointed tubulars and having a bottomhole assembly (BHA) coupled to an end thereof, the method comprising:

(a) providing a plurality of distributed sensors along at least a portion of the jointed tubulars and at the BHA, the distributed sensors being configured to measure one or more selected parameters of interest;

(b) measuring the selected parameters of interest;

(c) transmitting the measurements to a processor;

(d) processing the measurements using the processor to determine a physical condition for a selected segment of the drill string;

(e) providing a display device for pictorially representing an image of the selected segment of the drill string; and

(f) indicating the determined physical condition for the selected segment of the drill string by providing a visual signal on the image.

2. The method according to claim (1) wherein at least one of said distributed sensor is associated with a vulnerable location on the drill string.

3. The method according to claim (1) wherein the visual signal identifies an unacceptable determined physical condition.

4. The method of claim (1) wherein the visual signal includes a selected color.

5. The method of claim (1) wherein the visual signal includes a signal identifying the degree to which the determined physical condition varies from a predetermined norm.

6. The method according to claim 1 further comprising determining an adjustment to a selected drilling parameter if one or more of the determined physical conditions is outside a predetermined norm;

and displaying the adjustment on the display device.

7. The method according to claim 6 wherein the drilling parameter is selected from group consisting of weight-on-bit, fluid flow rate, drilling fluid viscosity, drilling fluid density, and drill bit rotational speed.

8. The method according to claim 1 wherein the processor determines the physical conditions for a plurality of selected drill string segments;

the display device pictorially represents images of the plurality of selected drill string segments; and

the determined physical conditions for the plurality of selected drill string segments is indicated by visual signals on the images.

9. The method according to claim 1 wherein the processor has an associated model, the processor cooperating with the model and utilizing the measurements from the plurality of distributed sensors to compute a combination of drilling parameters that when used for further drilling of the wellbore will yield at least one of (i) enhanced drilling rate, (ii) extended drilling assembly life, (iii) enhanced wellbore stability, (iv) improved hole quality, and (v) cause an unacceptable measured physical condition to return to within a predetermined norm;

and further comprising using the processor to cause the drilling system to alter the drilling parameters to the computed values for further drilling of the wellbore.

10. The method according to claim 1, wherein at least one of the distributed sensors measure a downhole parameter selected from the group comprising bit bounce, torque, shock, vibration, rotation, stick-slip, whirl, bending moment, and drill bit condition.

11. The method according to claim 1, wherein at least one of the distributed sensors is selected from the group comprising pressure sensor, accelerometer, magnetometer, gyroscopes, temperature sensor, force on bit sensors, and drill bit wear sensor.

12. The method according to claim 1, wherein at least one of the distributed sensors measures seismic energy generated by a seismic source.

13. The method according to claim 12 wherein the seismic energy is measured by one of:

(i) a geophone, (ii) a hydrophone, and (iii) an accelerometer.

14. The method according to claim 12 wherein the measured seismic energy is converted to seismic data;

and further comprising updating a seismic model based on the seismic data; and

adjusting the drilling direction based on the updated seismic model.

15. The method according to claim 1 wherein at least one of the distributed sensors measures one of (i) pressure;

and (i) density of a drilling fluid in the wellbore; and

further comprising;

determining one of;

(i) a pressure profile, and (ii) a density profile using the measured drill string parameter; and

adjusting one of (i) a pressure, (ii) flow rate, and (iii) density of the drilling fluid to control the equivalent circulating density of the drilling fluid.

16. A method of drilling a wellbore in a subterranean formation, comprising:

(a) conveying a drill string into the wellbore, the drill string including a plurality of tubular members and a bottomhole assembly (BHA) coupled to an end of the drill string, the BHA being adapted to disintegrate an earthen formation;

(b) distributing a plurality of receiver subs along at least a portion of the drill string, each receiver sub including a sensor for measuring a selected parameter of interest;

(c) measuring the selected parameter of interest using the sensors; and

(d) transmitting the sensor measurements to a processor.

17. The method according to claim 16 wherein the selected parameter of interest is one of:

(i) drill string acceleration, (ii) drill string strain, (iii) internal pressure in the drill string bore, (iv) external pressure in an annulus, (v) vibration, (vi) temperature, (vii) electrical field intensity, and (viii) and magnetic field intensity.

18. The method according to claim 16 wherein the data is transmitted to one of (i) a surface processor;

and (ii) a downhole processor.

19. The method according to claim 16 wherein the data is transmitted using a short-hop telemetry system using a telemetry module positioned in at least one of the receiver subs.

20. The method according to claim 16 wherein the measured parameter of interest is seismic energy generated by a seismic source.

21. The method according to claim 20 wherein the seismic energy is measured by one of:

(i) a geophone, (ii) a hydrophone, and (iii) an accelerometer.

22. The method according to claim 20 wherein the measured seismic energy is converted to seismic data;

and further comprising;

(f) updating a seismic model based on the seismic data; and

(g) adjusting the drilling direction based on the updated seismic model.

23. The method according to claim 16 wherein the plurality of receiver subs includes at least one seismic receiver sub having a seismic sensor for measuring acoustical energy;

and further comprising acoustically coupling the at least one receiver sub to a wellbore wall using an extensible arm that engages the wellbore wall.

24. The method according to claim 16 further comprising positioning a sensor for measuring acoustical energy on a non-rotating sleeve mounted on the receiver sub, the non-rotating sleeve allowing said sensor to remain substantially stationary relative to the wellbore wall when the drill string is rotating.

25. The method according to claim 16 wherein the measured parameter of interest includes one of (i) pressure;

and (i) density of a drilling fluid in the wellbore; and

further comprising;

determining one of;

(i) a pressure profile, and (ii) a density profile using the measured drill string parameter; and

adjusting one of (i) a pressure, (ii) flow rate, and (iii) density of the drilling fluid to control the equivalent circulating density of the drilling fluid.

26. The method according to claim 16 further comprising:

(f) activating a seismic source to generate seismic energy that is directed into the subterranean formation; and

(g) measuring the reflected seismic energy using the sensors.

27. The method according to claim 16 wherein the selected parameter of interest is seismic energy and further comprising time-stamping the seismic energy measurements with a clock module provided in each of the receiver subs.

28. The method according to claim 16 wherein each receiver sub is coupled to an end of a tubular member.

29. A system for drilling a wellbore, comprising:

(a) a drill string, said drill string including a plurality of jointed tubulars and a bottomhole assembly (BHA) coupled to an end thereof;

(b) a plurality of sensors distributed along at least a portion of said drill string, said distributed sensors being configured to measure one or more selected parameters of interest;

(c) a processor receiving the measurements from said plurality of distributed sensors and determining a physical condition for a segment of said drill string using at least some of the measurements; and

(d) a display device for pictorially representing an image of said segment of said drill string, said image including a visual signal indicating the determined physical condition for said segment.

30. The system according to claim (29) wherein said sensors are positioned at one or more vulnerable locations on said drill string.

31. The system according to claim (29) wherein said visual signal identifies an unacceptable determined physical condition.

32. The system according to claim (29) wherein said visual signal includes a selected color.

33. The system according to claim (29) wherein said visual signal includes a signal identifying the degree to which said determined physical condition varies from a predetermined norm.

34. The system according to claim (29) wherein said processor determines an adjustment to a selected drilling parameter if said determined physical condition is outside a predetermined norm;

and said display device displays said determined adjustment.

35. The system according to claim 34 wherein said drilling parameter is selected from group consisting of weight-on-bit, fluid flow rate, drilling fluid viscosity, drilling fluid density, and drill bit rotational speed.

36. The system according to claim 29 wherein said processor determines physical conditions for a plurality of drill string segments;

and said display device pictorially represents images of said plurality of drill string segments, said images including visual signals indicating the determined physical conditions for said plurality of drill string segments.

37. The system according to claim 29 wherein said processor has an associated model, said processor cooperating with said model and utilizing the measurements from said plurality of distributed sensors to compute a combination of drilling parameters that when used for further drilling of the wellbore will yield at least one of (i) enhanced drilling rate, (ii) extended drilling assembly life, (iii) enhanced wellbore stability, (iv) improved hole quality, and (v) causes an unacceptable determined physical condition to return to within a predetermined norm;

and wherein said processor alters the drilling parameters to the computed values for further drilling of the wellbore.

38. The system according to claim 29, wherein said parameters of interest are selected from one of:

bit bounce, torque, shock, vibration, rotation, stick-slip, whirl, bending moment, and drill bit condition.

39. The system according to claim 29, wherein at least one of said distributed sensors is selected from the group consisting of:

pressure sensor, accelerometer, magnetometer, gyroscopes, temperature sensor, force on bit sensors, and drill bit wear sensor.

40. The system according to claim 29, wherein at least one of said distributed sensors measures seismic energy generated by a seismic source.

41. The system according to claim 40 wherein the seismic energy is measured by one of:

(i) a geophone, (ii) a hydrophone, and (iii) an accelerometer.

42. The system according to claim 40 wherein the measured seismic energy is converted to seismic data;

and wherein said processor further comprises a seismic model based on the seismic data, said processor adjusting the drilling direction based on said seismic model.

43. The system according to claim 29 wherein at least one of said distributed sensors measures one of (i) pressure;

and (i) density of a drilling fluid in the wellbore; and

wherein said processor determines one of;

(i) a pressure profile, and (ii) a density profile using said selected measured parameter of interest.

44. A system for drilling a wellbore in a subterranean formation, comprising:

(a) a drill string, said drill string including a plurality of jointed tubulars and a bottomhole assembly (BHA) coupled to an end thereof;

(b) a plurality of receiver subs distributed along at least a portion of said plurality of jointed tubulars, said receiver subs including at least one sensor configured to measure one or more selected parameters of interest;

(c) a processor for processing the measurements from said distributed sensors; and

(e) a telemetry system for transmitting said measurements of said distributed sensors to said processor.

45. The system according to claim (44) wherein the selected parameter of interest is one of:

(i) drill string acceleration, (ii) drill string strain, (iii) internal pressure in the drill string bore, (iv) external pressure in an annulus, (v) vibration, (vi) temperature, (vii) electrical field intensity, and (viii) and magnetic field intensity.

46. The system according to claim (44) wherein said processor is positioned at one of (i) the surface;

and (ii) downhole.

47. The system according to claim (44) wherein said telemetry system includes a telemetry module positioned in at least one of said receiver subs.

48. The system according to claim (44) wherein said measured parameter of interest is seismic energy generated by a seismic source.

49. The system according to claim (48) wherein said seismic energy is measured by said sensor in one of said receiver subs, said sensor being one of:

(i) a geophone, (ii) a hydrophone, and (iii) an accelerometer.

50. The system according to claim (48) wherein said measured seismic energy is converted to seismic data;

and wherein said processor includes a seismic model based on said seismic data, said processor being configured to adjust drilling direction based on said seismic model.

51. The system according to claim (44) wherein at least one of said receiver subs includes an arm that extends from said receiver sub to acoustically couple a sensor for measuring acoustical energy to a wellbore wall.

52. The system according to claim (44) wherein at least one of said receiver subs includes a non-rotating sleeve mounted on the receiver sub, said non-rotating sleeve allowing said sensor associated with said receiver sub to remain substantially stationary relative to the wellbore wall when said drill string is rotating.

53. The system according to claim (44) wherein said measured parameter of interest is selected from one of (i) pressure;

and (i) density of a drilling fluid in the wellbore; and

said processor determines one of;

(i) a pressure profile, and (ii) a density profile using the measured drill string parameter.

54. The system according to claim (44) further comprising:

(a) a seismic source to generate seismic energy that is directed into the subterranean formation; and

(b) wherein said plurality of receiver subs includes at least one seismic receiver sub provided with a sensor for measuring seismic energy.

55. The system according to claim (54) wherein said at least one seismic receiver sub includes a clock module for time-stamping the seismic energy measurements.

56. The system according to claim (44) wherein each said receiver sub is coupled to an end of said jointed tubular.