LANNING CURTIS (US)
KURTHY JEFFREY (US)
| WO2018129252A1 | 2018-07-12 | |||
| WO2018005402A1 | 2018-01-04 |
| US20070251726A1 | 2007-11-01 | |||
| US20160281431A1 | 2016-09-29 | |||
| US9624727B1 | 2017-04-18 | |||
| US20140131106A1 | 2014-05-15 |
| What is claimed is: 1. A bottomhole assembly 10 comprising: a drill bit 20, said drill bit having an outer diameter, said drill bit joined to a bit box 18 thereby defining a joint 24 between said drill bit and said bit box; a flex shaft 12 having a flex section 12c, said flex section having a first upper end 12d and a second lower end 12e, said flex section length between said first upper end and said second lower end is about 72 inches to about 122 inches; a stabilizer 14; and, a push-the-bit rotary steerable system 16, said push-the-bit rotary steerable system having at least three steering arms 22, said steering arms movable from a retracted position to an extended position, said steering arms having a lower end 22a. 2. The bottomhole assembly of claim 1, wherein said stabilizer is located a distance of about 52 inches to about 72 inches when measured from the center of said stabilizer to said joint between said drill bit and said bit box. 3. The bottomhole assembly of claim 1, wherein said stabilizer is located a distance of about 60 inches to about 67 inches when measured from the center of said stabilizer to said joint between said drill bit and said bit box. 4. The bottomhole assembly of claim 1, wherein said push-the-bit rotary steerable system is positioned a distance of about 12 to about 32 inches from said joint between said drill bit and said bit box when measured from the lower end of said steering arms in the retracted position to the joint defined by the bit box and the bit. 5. The bottomhole assembly of claim 1, wherein said push-the-bit rotary steerable system is positioned a distance of about 17 to about 27 inches from said joint between said drill bit and said bit box when measured from the lower end of said steering arms in the retracted position to the joint defined by the bit box and the bit. 6. The bottomhole assembly of claim 1, wherein said push-the-bit rotary steerable system is positioned a distance of about 20 to about 24 inches from said joint between said drill bit and said bit box when measured from the lower end of said steering arms in the retracted position to the joint defined by the bit box and the bit. 7. The bottomhole assembly of claim 1, wherein said steering arms in the extended position extend outward from said retracted position a distance of about 3.5% to about 8% of outer diameter of said drill bit. 8. The bottomhole assembly of claim 1, wherein said steering arms in the extended position extend outward from said retracted position a distance of about 5% to about 8% of the outer diameter of said drill bit. 9. The bottomhole assembly of claim 1, wherein said steering arms in the extended position extend outward from said retracted position a distance of about 6.5% of outer the diameter of said drill bit. 10. The bottomhole assembly of claim 1, wherein the distance between said second lower end 12e of said flex shaft and said joint between said drill bit and said bit box is between about 81 inches and about 110 inches. 11. The bottomhole assembly of claim 1, wherein the distance between said second lower end 12e of said flex shaft and said joint between said drill bit and said bit box is between about 91 inches and about 101 inches. 12. The bottomhole assembly of claim 1, wherein the distance between said second lower end 12e of said flex shaft and said joint between said drill bit and said bit box is between about 91 inches and about 97 inches. 13. The bottomhole assembly of claim 1, wherein the distance of said flex section between said first upper end and said second lower end is about 102 inches to about 122 inches. 14. The bottomhole assembly of claim 1, wherein the distance of said flex section between said first upper end and said second lower end is about 107 inches to about 117 inches. 15. The bottomhole assembly of claim 1, further comprising a second flex shaft. 16. The bottomhole assembly of claim 1, wherein said stabilizer has an outer diameter that is less than the outer diameter of the drill bit. 17. The bottomhole assembly of claim 1, wherein said outer diameter of said stabilizer is between about 0.0625 inch and about 0.5 inch smaller than the outer diameter of the drill bit. 18. The bottomhole assembly of claim 1, wherein said outer diameter of said stabilizer is between about 0.0625 inch and about 0.25 inch smaller than the outer diameter of the drill bit. 19. A bottomhole assembly comprising: a drill bit 20, said drill bit having an outer diameter, said drill bit joined to a bit box 18 thereby defining a joint between said drill bit and said bit box; a flex shaft 12 having a flex section, said flex section having a first upper end 12d and a second lower end 12e, said flex section length between said first upper end and said second lower end is about 72 inches to about 122 inches; a stabilizer 14; and, a push-the-bit rotary steerable system 16, said push-the-bit rotary steerable system having at least three steering arms, said steering arms movable from a retracted position to an extended position, said steering arms having a lower end 22a and said push-the-bit rotary steerable system is positioned a distance of about 12 inches to about 32 inches from said joint between said drill bit and said bit box when measured from the lower end of said steering arms in the retracted position to the joint defined by the bit box and the bit. 20. The bottomhole assembly of claim 19, wherein said stabilizer is located a distance of about 52 inches to about 72 inches when measured from the center of said stabilizer to said joint between said drill bit and said bit box. 21. The bottomhole assembly of claim 19, wherein said stabilizer is located a distance of about 60 inches to about 67 inches when measured from the center of said stabilizer to said joint between said drill bit and said bit box. 22. The bottomhole assembly of claim 19, wherein said push-the-bit rotary steerable system is positioned a distance of about 17 to about 27 inches from said joint between said drill bit and said bit box when measured from the lower end of said steering arms in the retracted position to the joint defined by the bit box and the bit. 23. The bottomhole assembly of claim 19, wherein said push-the-bit rotary steerable system is positioned a distance of about 20 to about 24 inches from said joint between said drill bit and said bit box when measured from the lower end of said steering arms in the retracted position to the joint defined by the bit box and the bit. 24. The bottomhole assembly of claim 19, wherein said steering arms in the extended position extend outward from said retracted position a distance of about 3.5% to about 8% of outer diameter of said drill bit. 25. The bottomhole assembly of claim 19, wherein said steering arms in the extended position extend outward from said retracted position a distance of about 5% to about 7% of the outer diameter of said drill bit. 26. The bottomhole assembly of claim 19, wherein said steering arms in the extended position extend outward from said retracted position a distance of about 6.5% of outer the diameter of said drill bit. 27. The bottomhole assembly of claim 19, wherein the distance between said second lower end 12e of said flex shaft and said joint between said drill bit and said bit box is between about 81 inches and about 110 inches. 28. The bottomhole assembly of claim 19, wherein the distance between said second lower end 12e of said flex shaft and said joint between said drill bit and said bit box is between about 91 inches and about 101 inches. 29. The bottomhole assembly of claim 19, wherein the distance between said second lower end 12e of said flex shaft and said joint between said drill bit and said bit box is between about 91 inches and about 97 inches. 30. The bottomhole assembly of claim 19, wherein the distance of said flex section between said first upper end and said second lower end is about 102 inches to about 122 inches. 31. The bottomhole assembly of claim 19, wherein the distance of said flex section between said first upper end and said second lower end is about 107 inches to about 117 inches. 32. The bottomhole assembly of claim 19, further comprising a second flex shaft. 33. The bottomhole assembly of claim 19, wherein said stabilizer has an outer diameter that is less than the outer diameter of the drill bit. 34. The bottomhole assembly of claim 19, wherein said outer diameter of said stabilizer is between about 0.0625 inch and about 0.5 inch smaller than the outer diameter of the drill bit. 35. The bottomhole assembly of claim 19, wherein said outer diameter of said stabilizer is between about 0.0625 inch and about 0.25 inch smaller than the outer diameter of the drill bit. 36. A bottomhole assembly comprising: a drill bit 20, said drill bit having an outer diameter, said drill bit joined to a bit box 18 thereby defining a joint between said drill bit and said bit box; a flex shaft 12 having a flex section, said flex section having a first upper end 12d and a second lower end 12e, said flex section length between said first upper end and said second lower end is about 72 inches to about 122 inches; a stabilizer 14, said stabilizer is located a distance of about 52 inches to about 72 inches when measured from the center of said stabilizer to said joint between said drill bit and said bit box; and, a push-the-bit rotary steerable system 16, said push-the-bit rotary steerable system having at least three steering arms, said steering arms movable from a retracted position to an extended position, said steering arms having a lower end 22a and said push-the-bit rotary steerable system is positioned a distance of about 12 inches to about 32 inches from said joint between said drill bit and said bit box when measured from the lower end of said steering arms in the retracted position to the joint defined by the bit box and the bit. 37. The bottomhole assembly of claim 36, wherein said stabilizer is located a distance of about 60 inches to about 67 inches when measured from the center of said stabilizer to said joint between said drill bit and said bit box. 38. The bottomhole assembly of claim 36, wherein said push-the-bit rotary steerable system is positioned a distance of about 17 to about 27 inches from said joint between said drill bit and said bit box when measured from the lower end of said steering arms in the retracted position to the joint defined by the bit box and the bit. 39. The bottomhole assembly of claim 36, wherein said push-the-bit rotary steerable system is positioned a distance of about 20 to about 24 inches from said joint between said drill bit and said bit box when measured from the lower end of said steering arms in the retracted position to the joint defined by the bit box and the bit. 40. The bottomhole assembly of claim 36, wherein said steering arms in the extended position extend outward from said retracted position a distance of about 3.5% to about 8% of outer diameter of said drill bit. 41. The bottomhole assembly of claim 36, wherein said steering arms in the extended position extend outward from said retracted position a distance of about 5% to about 7% of the outer diameter of said drill bit. 42. The bottomhole assembly of claim 36, wherein said steering arms in the extended position extend outward from said retracted position a distance of about 6.5% of outer the diameter of said drill bit. 43. The bottomhole assembly of claim 36, wherein the distance between said second lower end 12e of said flex shaft and said joint between said drill bit and said bit box is between about 81 inches and about 110 inches. 44. The bottomhole assembly of claim 36, wherein the distance between said second lower end 12e of said flex shaft and said joint between said drill bit and said bit box is between about 91 inches and about 101 inches. 45. The bottomhole assembly of claim 36, wherein the distance between said second lower end 12e of said flex shaft and said joint between said drill bit and said bit box is between about 91 inches and about 97 inches. 46. The bottomhole assembly of claim 36, wherein the distance of said flex section between said first upper end and said second lower end is about 102 inches to about 122 inches. 47. The bottomhole assembly of claim 36, wherein the distance of said flex section between said first upper end and said second lower end is about 107 inches to about 117 inches. 48. The bottomhole assembly of claim 36, further comprising a second flex shaft. 49. The bottomhole assembly of claim 36, wherein said stabilizer has an outer diameter that is less than the outer diameter of the drill bit. 50. The bottomhole assembly of claim 36, wherein said outer diameter of said stabilizer is between about 0.0625 inch and about 0.5 inch smaller than the outer diameter of the drill bit. 51. The bottomhole assembly of claim 36, wherein said outer diameter of said stabilizer is between about 0.0625 inch and about 0.25 inch smaller than the outer diameter of the drill bit. 52. A bottomhole assembly positioned within a borehole comprising: a drill bit 20, said drill bit having an outer diameter, said drill bit joined to a bit box 18 thereby defining a joint between said drill bit and said bit box; a flex shaft 12 having a flex section, said flex section having a first upper end 12d and a second lower end 12e, said flex section length is about 72 inches to about 122 inches, the distance between said second lower end 12b and said joint between said drill bit and said bit box is between about 81 inches and about 110 inches; a stabilizer 14, said stabilizer having an outer diameter which is less than the outer diameter of said drill bit, said stabilizer is located a distance of about 52 inches to about 72 inches when measured from the center of said stabilizer to said joint between said drill bit and said bit box; and, a push-the-bit rotary steerable system 16, said push-the-bit rotary steerable system having at least three steering arms, said steering arms movable from a retracted position to an extended position, when extended said steering arms extending outward from said retracted position a distance of about 3.5% to about 8% of outer diameter of said drill bit, said push-the-bit rotary steerable system is positioned a distance of about 12 inches to about 32 inches from said joint between said drill bit and said bit box when measured from the lower end of said steering arms in the retracted position to the joint defined by the bit box and the bit. 53. The bottomhole assembly of claim 52, wherein said outer diameter of said stabilizer is between about 0.0625 inch and about 0.5 inch smaller than the outer diameter of the drill bit. 4. The bottomhole assembly of claim 52, wherein said outer diameter of said stabilizer is between about 0.0625 inch and about 0.25 inch smaller than the outer diameter of the drill bit. |
PRIORITY CLAIM
[0001] This Application claims priority and incorporates fully the disclosure of U.S. Provisional Application Serial No. 62/701,222 filed July 20, 2018, titled“IMPROVED BHA”.
BACKGROUND
[0002] Directional drilling can be accomplished using bottomhole assemblies (BHA) which incorporate either a bent motor or a Rotary Steerable Systems (RSS). Conventional BHAs consist of a bent motor and MWD which provide the capability of creating curves on build rates between 3° to 18° per 100’. However, using the sliding technique of conventional technology creates significant wellbore tortuosity and ledges when transitioning between sliding/rotating. The use of the more advanced RSS technology in the BHA allows one to create more complex, smoother wellbores having longer laterals. When transitioning from a vertical borehole to a horizontal borehole as depicted in FIG. 5, currently available RSS technology generally limits maximum build up rates (BUR), i.e. the curvature of the borehole, to a range of three degrees to eight degrees per one hundred feet of borehole (6° per 100’ average). Thus, the length of the transition from a vertical borehole to a horizontal borehole can result in the kick-off point of the directional drilling operation beginning sooner than desired.
SUMMARY
[0003] Disclosed herein is an improved bottomhole assembly suitable for use in directional drilling a borehole. The BHA comprises a drill bit 20 having an outer diameter. The drill bit is joined to a bit box 18 thereby defining a joint between the drill bit and the bit box. The BHA also includes a flex shaft 12 having a flex section. The flex section has a length of about 72 inches to about 122 inches as measured from a first upper end 12d to a second lower end 12e. The distance between lower end 12e and the joint between the drill bit and the bit box is between about 81 inches and about 110 inches. Also included in the improved BHA is a stabilizer 14. The stabilizer has an outer diameter which is less than the outer diameter of the drill bit. The stabilizer is located a distance of about 52 inches to about 72 inches when measured from the center of the stabilizer to the joint between the drill bit and the bit box. Further, the BHA includes a push-the-bit rotary steerable system 16. The push-the-bit rotary steerable system has at least three steering arms. The steering arms are movable from a retracted position to an extended position. When extended, the steering arms extending outward from the rotary steerable system a distance of about 3.5% to about 8% of the outer diameter of the drill bit. The push-the-bit rotary steerable system is positioned a distance of about 12 to about 32 inches when measured from the end of the steering arms in the retracted position to the joint between the drill bit and the bit box.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] FIG. 1 is a side view of an improved bottomhole assembly.
[0005] FIG. 2 is a side view of the lower end of the improved bottomhole assembly.
[0006] FIG. 3 is a side view of the bit box, RSS and lower stabilizer components of the improved bottomhole assembly.
[0007] FIG. 4 is a three dimensional depiction of two boreholes at different build rates originating from a single vertical borehole.
[0008] FIG. 5 is a graphical depiction of the improved build rate provided by the improved bottomhole assembly. DETAILED DESCRIPTION
[0009] This disclosure provides an improved BHA 10 configured to produce a significantly shorter drilling radius in the transition from the vertical borehole to the horizontal borehole. BHA 10 includes a flex shaft 12, a stabilizer 14, a push-the-bit rotary steerable system 16, a bit box 18 and a drill bit 20. BHA 10 may also include additional elements common to drilling operations. Such additional elements will be positioned uphole of flex shaft 12.
[0010] Flex shaft 12 includes an upper upset 12a and a lower upset 12b which function as tool joints. Intermediate to upper upset 12a and lower upset 12b is the flex section 12c of flex shaft 12. Flex section 12c corresponds to the decreased diameter portion of flex shaft 12. Flex section 12c has a length of about 72 inches to about 122 inches as measured from first upper end 12d to second lower end 12e. Typically, flex section 12c has a length F of about 102 inches to about 122 inches. More preferably, flex section 12c has a length of about 112 inches. Distance F may vary within the indicated range based on the formation and target design of the final borehole. Flex shaft 12 is characterized by a typical industry flex joint cross-section with an OD of -5.25” and an ID of -2.5-3.5”. As it is incorporated into the RSS, it is made of non-magnetic material.
[0011] The length of flex shaft 12 directly influences the effective build rates. Use of a longer flex shaft 12 will increase effective build rates, i.e. will reduce the radius of curvature. Decreasing the length of flex shaft 12 will decrease the build rate while allowing for an increase in the rate of penetration and a smoother borehole.
[0012] In an alternative embodiment, flex shaft 12 may be replaced with two or more flex shafts 12. When using two or more flex shafts 12, the total length of the flex sections 12c should be in the same range as defined above with regard to a single flex section 12c. When using multiple flex shafts 12 each flex shaft 12 will be characterized by a typical industry flex joint cross-section with a OD of -5.25” and a ID of -2.5-3.5” when operating with a 7.5” to 8.75” drill bit. As it is incorporated into the RSS, it is made of non-mag material.
[0013] Rotary steerable system 16 includes at least three steering arms 22. Steering arms 22 are movable from a retracted position to an extended position. Typically, rotary steerable system 16 will have four movable steering arms 22. A hydraulic piston, not shown, commonly actuates steering arms 22; however, rotary steerable system 16 may use any arrangement desired to actuate steering arms 22. Devices and control systems for actuating and controlling steering arms 22 are well known to those skilled in the art and will not be discussed herein. As discussed in more detail below, one improvement provided herein by rotary steerable system 16 relates to the location of rotary steerable system 16 within BHA relative to stabilizer 14 and the joint 24 between bit box 18 and drill bit 20.
[0014] When used in BHA 10, steering arms 22 of rotary steerable system 16 will be configured to extend outwards from rotary steerable system 16, when measured at steering arms 22, a distance equal to about 3.5% to about 8% of the outside diameter of drill bit 20. For example, when used with an eight-inch drill bit 20, steering arms 22 will extend outward from the retracted position a distance of about 0.30 inch to about 0.68 inch. Likewise, for a 13.5-inch diameter drill bit 20, steering arm extension will be between about 0.47 inch and 1.08 inch. The optimum extension of steering arms 22 will be determined by the formation and target design of the final borehole. Typically, a steering arm extension of about 6.5% of drill bit diameter will provide the desired BUR.
[0015] In addition to providing a rotary steerable system 16, the disclosed BHA 10 utilizes a unique arrangement of components to provide the desired improvement in BUR. With reference to FIGS. 2 and 3, the distance S is defined as the distance between the center of stabilizer 14 and the joint 24 defined by the connection between bit 20 and bit box 18. Distance S is at least 52 inches but not more than 72 inches. Typically, distance S will be 63.7 inches. The distance R, as measured from the lower end 22a of steering arms 22 in the retracted position to joint 24 defined by connection between bit box 18 and bit 20, is at least 12 inches but not more than 32 inches. Typically, distance R will be 21.9 inches. The distance B is defined as the distance between the start of diameter transition at lower upset 12b, i.e. lower end 12e on flex shaft 12 and the joint 24 defined by the connection between bit 20 and bit box 18 is at least 81 inches but not more than 110 inches. Typically, distance B will be between 91 inches and 101 inches. Frequently, the desired length of distance B is 93.7 inches. Stabilizer 14 has an outer diameter that is smaller than the outer diameter of drill bit 20. In general, the outer diameter of stabilizer 14 is between 0.0625 and 0.5 inch smaller than the outer diameter of drill bit 20. Typically, the outer diameter of stabilizer 14 is about 0.125 inch smaller than the outer diameter of drill bit 20.
[0016] With reference to FIGS. 4-5, BHA 10, as described above, provides improved build rates. In particular, adjustment of distances R, S and B define the build rate capability of BHA 10. In general, distance S acts as the fulcrum or pivot point for generating the radius of the non vertical borehole. A shorter distance S in conjunction with a longer distance F will provide improved build rates. The reduced distance S and increased distance F and the extended reach of steering arms 22 enable an even further improved average build rate over the shortening of S and lengthening of F alone. The combination of these components provides a build rate increase from about 6° per 100 feet to about 12° per 100 feet. If desired, the optimization of distances S, F and selection of an increased extension of steering arms 22 equivalent to 8% of the diameter of drill bit 20 can provide a build rate of up to about 15° per 100 feet of penetration. Additionally, the shortening of distances R, S and B and the increased extension of steering arms 22 reduces the likelihood of stabilizer 14 hanging up during directional drilling operations. Hanging up of stabilizer 14 would limit the build up capability of improved BHA 10.
[0017] With reference to FIG. 4, the comparison of borehole 40 to borehole 50 demonstrates the improved build rate provided by BHA 10. When compared to borehole 50, the shorter radius of borehole 40 provides an increase in the useful horizontal borehole of 478 feet. In other words, the shorter radius of borehole 40 reduces the time and distance required to operate BHA 10 in a directional drilling mode. Thus, the improved BHA disclosed herein enables a greater production zone for extraction of subterranean hydrocarbons.
[0018] Continuing with FIG. 4, theoretical borehole 40 represents a borehole drilled with BHA 10 configured with an 8.75 inch drill bit 20, a steering arm 22 extension of 0.55 inch (corresponds to a distance of 6.25% beyond the 8.75 inch drill bit), an R distance of 21.9 inches; S distance of 63.7 inches; an F distance of 107.8 inches; and, a B distance of 93.7 inches in a borehole having a diameter between about five inches and 17.5 inches. The resulting borehole will have a BUR of 12° per 100 feet and a radius of 477 feet. In contrast, theoretical borehole 50 represents a borehole drill with a prior art configuration of an RSS based BHA. The prior art configuration RSS based BHA would have an 8.75 inch drill bit, a steering arm extension of 0.41 inch (corresponds to a 4.7% extension beyond the 8.75 inch drill bit), an R distance of 22.0 inches; S distance of 113.2 inches; an F distance of 107.8 inches; and, a B distance of 270.5 inches in a borehole having a diameter between about five inches and 17.5 inches.
[0019] FIG. 5 provides a build rate graph corresponding to the three dimensional depiction of theoretical boreholes 40, 50. Line 70 corresponds to borehole 50 and reflects the 6° per 100 feet build rate which would be produced using a BHA with a conventional RSS. In contrast, line 60 corresponds to wellbore 40 and demonstrates that improved BHA 10 will provide the ability to generate a build rate of 12° per 100 feet.
[0020] Thus, as represented by FIG. 4, the shorter radius of wellbore 40 will provide wellbore 40 with a longer horizontal component when compared to wellbore 50. As depicted in FIG. 5, the horizontal component of wellbore 40, represented by line 60, begins at point 62 whereas the horizontal component of wellbore 50, represented by line 70, begins at point 72. Thus, the resulting horizontal production zone of wellbore 40 will be approximately 478 feet longer than the horizontal production zone of wellbore 50. Additionally, the shorter directional drilling radius provided by BHA 10 allows the drilling operator to minimize directional drilling operations as the kickoff point of directional drilling may be delayed thereby extending the lower cost vertical wellbore. The kickoff point can be delayed as the reduced radius for drilling operations allows one to achieve the same location for the horizontal wellbore.
[0021] Other embodiments of the present invention will be apparent to one skilled in the art. As such, the foregoing description merely enables and describes the general uses and methods of the present invention. Accordingly, the following claims define the true scope of the present invention.