Managed pressure drilling

• US 20060157282A1
• Filed: 10/20/2005
• Published: 07/20/2006
• Est. Priority Date: 05/28/2002
• Status: Active Grant

• Current Assignee: Weatherford Technology Holdings, LLC (Weatherford International PLC)
• Original Assignee: Weatherford Technology Holdings, LLC (Weatherford International PLC)
• Inventors: Fuller, Tom, Rooyakkers, Roy W., Skinner, Graham, Bailey, Thomas F., Haugen, David M., Smith, Kevin W., Brunnert, David J., Tilton, Frederick T., Bansal, Ram K.
• Granted Patent: US 8,955,619 B2
• Time in Patent Office: Days
• US Class Current: 175/65
• CPC Class Codes: E21B 21/08 Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure valve arrangements therefor E21B21/10
• CPC Class Codes: E21B 21/085 Underbalanced techniques, i.e. where borehole fluid pressure is below formation pressure
• CPC Class Codes: E21B 21/14 using liquids and gases, e.g. foams
• CPC Class Codes: E21B 33/14 for cementing casings into boreholes
• CPC Class Codes: E21B 4/02 Fluid rotary type drives

Abstract

Embodiments of the present invention include methods and apparatus for dynamically controlling pressure within a wellbore while forming the wellbore. In one aspect, one or more pressure control apparatus are used to maintain desired pressure within the wellbore while drilling the wellbore. In another aspect, pressure is dynamically controlled while drilling using foam to maintain a substantially homogenous foam flow regime within the wellbore annulus for carrying cuttings from the wellbore.

Claims

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

drilling the wellbore using a tubular body;

circulating a foam through the tubular body and into an annulus between the outer diameter of the tubular body and the wellbore; and

maintaining a substantially homogenous foam flow regime in the annulus using one or more pressure control mechanisms.

2. The method of claim 1, wherein maintaining the substantially homogenous foam flow regime comprises maintaining an ability of the foam to transport cuttings from the formation.

3. The method of claim 1, wherein maintaining the substantially homogenous foam flow regime comprises maintaining foam quality.

4. The method of claim 3, wherein foam quality in the annulus is maintained in a range of from approximately 0.52 to approximately 0.96.

5. The method of claim 1, wherein maintaining the substantially homogenous foam flow regime comprises maintaining foam viscosity.

6. The method of claim 1, wherein maintaining the substantially homogenous foam flow regime comprises maintaining foam shear strength.

7. The method of claim 1, wherein at least one of the one or more pressure control mechanisms is located at an outflow of the foam from the annulus at a surface of the wellbore.

8. The method of claim 7, wherein at least one of the one or more pressure control mechanisms is a choke.

9. The method of claim 1, wherein maintaining the substantially homogenous foam flow regime in the annulus using one or more pressure control mechanisms comprises choking an outflow of foam from the annulus.

10. The method of claim 1, wherein at least one of the one or more pressure control mechanisms is disposed in the annulus.

11. The method of claim 1, wherein at least one of the one or more pressure control mechanisms is a downhole choke.

12. The method of claim 1, wherein at least one of the one or more pressure control mechanisms is an equivalent circulation density tool.

13. The method of claim 1, wherein maintaining the substantially homogenous foam flow regime in the annulus comprises defining flow characteristics of the foam from a bottom of the wellbore to a surface of the wellbore.

14. The method of claim 1, wherein maintaining the substantially homogenous foam flow regime in the annulus comprises maintaining transportability of the foam throughout the annulus.

15. A method of changing pressure within a wellbore, comprising:

forming the wellbore using a drill string;

circulating fluid into an annulus between an outer diameter of the drill string and a wall of the wellbore while forming the wellbore; and

selectively choking the fluid in the annulus, thereby changing a pressure profile of the fluid flowing in the annulus.

16. The method of claim 15, wherein a downhole choke is use to selectively choke the fluid.

17. The method of claim 16, wherein the downhole choke is located at a surface of the wellbore.

18. The method of claim 16, wherein the downhole choke is an inner diameter restriction within the drill string which exerts a back-pressure into the annulus.

19. The method of claim 16, wherein the downhole choke is an outer diameter restriction located on the drill string which exerts a back-pressure below the downhole choke in the annulus.

20. The method of claim 15, further comprising lifting of the fluid within the annulus.

21. The method of claim 20, wherein an equivalent circulation density reduction tool is used to lift the fluid.

22. The method of claim 21, wherein the equivalent circulation density reduction tool is disposed downstream of the fluid from the downhole choke.

23. The method of claim 21, wherein the equivalent circulation density reduction tool is disposed upstream of the fluid from the downhole choke.

24. The method of claim 21, wherein the equivalent circulating density reduction tool transfers a weight of the fluid from a bottom of the wellbore to a hook.

25. The method of claim 20, wherein the lifting and the choking is performed by one selectively operable pressure control mechanism.

26. The method of claim 20, wherein a lifting point and a choking point within the annulus straddle an area of interest in a formation.

27. The method of claim 20, further comprising selectively choking fluid flow through the annulus and selectively lifting fluid flow within the annulus to increase or decrease pressure of the fluid within the annulus.

28. The method of claim 27, further comprising maintaining fluid pressure substantially adjacent to an area of interest in a formation.

29. The method of claim 15, wherein maintaining fluid pressure substantially adjacent to an area of interest in a formation.

30. The method of claim 29, further comprising determining real-time pressure conditions in the annulus using one or more pressure sensors.

31. The method of claim 30, further comprising communicating the pressure conditions in the annulus to an operating unit.

32. The method of claim 31, further comprising using the operating unit to alter the choking to manipulate the pressure profile of the fluid along the annulus.

33. The method of claim 31, further comprising communicating one or more signals from the operating unit to the downhole choke to operate the downhole choke at the pressure profile.

34. The method of claim 33, wherein communicating from the operating unit to the downhole choke is accomplished by one or more signals through a wall of the drill string.

35. The method of claim 15, further comprising automatically adjusting the downhole choke to change the pressure profile of the fluids in the annulus.

36. The method of claim 15, wherein the pressure profile is changed during make-up of the drill string.

37. The method of claim 15, wherein the donwhole choke is an annular flow restriction located downhole on the outer diameter of the drill string.

38. The method of claim 37, further comprising dynamically adjusting the amount of restriction in annular flow downhole to change the pressure profile.

39. The method of claim 37, further comprising dynamically adjusting the longitudinal location of the annular flow restriction relative to the drill string to change the pressure profile.

40. The method of claim 15, wherein the downhole choke comprises a downhole separating device within the drill string for separating the fluid into an at least substantially liquid stream for traveling further within the drill string and an at least substantially gas stream conveyed outside the drill string through a wall of the drill string.

41. The method of claim 40, wherein the fluid is foam.

42. The method of claim 15, further comprising:

separating the drilling fluid downhole into a first stream and a second stream;

flowing the first stream through a wall of the drill string into the annulus; and

providing lifting force to the second stream flowing through the annulus to a surface of the wellbore by merging the first stream with the second stream.

43. The method of claim 42, wherein an amount of lifting force is dynamically provided due to a changing fluid-separating location within the wellbore.

44. The method of claim 42, wherein a downhole separator located in the drill string accomplishes the separating, and wherein a changing location of the drill string relative to the wellbore during the forming of the wellbore dynamically alters fluid pressure within the annulus.

45. The method of claim 15, wherein the downhole choke comprises a first fluid stream combinable downhole with the fluid flowing outside the drill string, the first fluid stream having a density less than the fluid.

46. The method of claim 45, further comprising lifting the fluid within the annulus by introducing the first fluid stream into the annulus at a downhole location to combine the first fluid stream with the fluid.

47. The method of claim 46, wherein an injecting device is inserted into the annulus to introduce the first fluid stream into the annulus.

48. The method of claim 45, further comprising lifting the fluid within the annulus by:

introducing the first fluid stream into the wellbore between a wellbore wall and an outer diameter of a tubular member located substantially coaxial with the wellbore; and

circulating the first fluid stream around the tubular member to combine with the fluid flowing up between an inner diameter of the tubular member and the drill string.

49. The method of claim 45, wherein the first fluid stream reduces a fluid pressure of the fluid flowing downhole.

50. The method of claim 45, wherein the first fluid stream is a gas stream.

51. The method of claim 15, further comprising a downhole lifting device for transferring energy from a first fluid stream flowing through the drill string to a second fluid stream flowing through the annulus, thereby reducing a fluid pressure of the second fluid stream below the downhole lifting device.

52. The method of claim 51, further comprising opening an alternate fluid flow path through a wall of the drill string upon blockage of a fluid flow path through a lower end of the drill string to allow the downhole lifting device to continue the flow of the second fluid stream below the downhole lifting device.

53. The method of claim 51, wherein the downhole lifting device comprises one or more annular flow ports for selectively allowing fluid flow through the annulus.

54. A method of forming a wellbore, comprising:

inserting a tubular body into a wellbore formed in an earth formation;

circulating a foamed cement through the tubular body and into an annulus between the outer diameter of the tubular body and the wellbore; and

tailoring a density of the foamed cement along the annulus using one or more pressure control mechanisms.

55. The method of claim 54, further comprising curing the foamed cement at hydrostatic conditions to set the tubular body within the wellbore.