Well bore conditioner and stabilizer

Abstract

A drill string stabilizer for use in a well bore includes a tubular body with a stabilizer axis, a first roller including a first roller axis spaced apart from the stabilizer axis of the tubular body, and at least a second roller spaced longitudinally apart from the first roller, the at least a second roller including a second roller axis spaced apart from the stabilizer axis of the tubular body. The first roller is angularly offset from the at least the second roller around a circumference of the tubular body.

Claims

1. A drill string stabilizer for use in a well bore, the well bore having a well bore axis and a well bore wall, comprising: a tubular body with a stabilizer axis; a first roller including a first roller axis spaced a first fixed distance apart from the stabilizer axis of the tubular body; and, at least a second roller spaced longitudinally apart from the first roller, the at least the second roller including a second roller axis spaced a second fixed distance apart from the stabilizer axis of the tubular body; wherein the first roller is angularly offset from the at least the second roller around a circumference of the tubular body; and, a plenum that separates the first roller and the at least the second roller, wherein a pass-through diameter of the drill string stabilizer is smaller than a gauge diameter of the drill string stabilizer.

2. The drill string stabilizer of claim 1, wherein the first roller and the at least the second roller further comprises at least one well bore contacting surface.

3. The drill string stabilizer of claim 2, wherein the at least one well bore contacting surface is a polycrystalline diamond compact (PDC) surface.

4. The drill string stabilizer of claim 1, wherein the first roller and the at least the second roller provide an open line-of-sight path through the first roller and the at least the second roller.

5. The drill string stabilizer of claim 1, wherein the first roller and the at least the second roller further comprise at least two protrusions extending from each of the first roller and the at least the second roller.

6. The drill string stabilizer of claim 5, wherein the at least two protrusions of the first roller are not in line with the protrusions of the at least the second roller.

7. The drill string stabilizer of claim 1, wherein the first roller is diametrically opposed to the at least the second roller.

8. The drill string stabilizer of claim 1, wherein the first roller includes a race and the at least a second roller includes another race.

9. The drill string stabilizer of claim 8, wherein the first roller and the at least a second roller are able to freely rotate within the race and the another race, respectively.

10. The drill string stabilizer of claim 8, further comprising a bearing positioned between the race and the first roller.

11. A bottom hole assembly (BHA) for use in a well bore, the well bore having a well bore axis and a well bore wall, comprising: a well bore drill; and, at least the drill string stabilizer of claim 1.

12. A drill string stabilizer for use in a well bore, the well bore having a well bore axis and a well bore wall, comprising: a tubular body with a stabilizer axis; a first stabilizing element including a first stabilizing element axis offset a first fixed distance from the stabilizer axis; and, at least the second stabilizing element spaced apart from the first stabilizing element, the at least a second stabilizing element including a second stabilizing element axis offset a second fixed distance from the stabilizer axis; wherein the first stabilizing element is angularly offset from the at least the second stabilizing element around a circumference of the tubular body; and, a plenum that separates the first stabilizing element and the at least the second stabilizing element, wherein a pass-through diameter of the drill string stabilizer is smaller than a gauge diameter of the drill string stabilizer.

13. The drill string stabilizer of claim 12, wherein the first stabilizing element and the at least the second stabilizing element comprise a stationary wear pad.

14. The drill string stabilizer of claim 12, wherein the first stabilizing element comprises a first roller and wherein the at least the second stabilizing element comprises at least a second roller.

15. The drill string stabilizer of claim 12, wherein the first stabilizing element is diametrically opposed to the at least the second stabilizing element.

Description

DESCRIPTION OF THE FIGURES

(1) FIG. 1 Depicts a first embodiment of a conditioning and stabilizing device with two stages.

(2) FIG. 2 Depicts the first embodiment of the device shown in FIG. 1 viewed down the drill string.

(3) FIG. 3 Depicts a single stage of the first embodiment of the device shown in FIG. 1.

(4) FIG. 4 Depicts a single stage of the first embodiment of the device shown in FIG. 1 viewed down the drill string.

(5) FIG. 5 Depicts a second embodiment of a stabilizing device with two eccentric stabilizers.

(6) FIG. 6 Depicts a side view the second embodiment within the well bore.

(7) FIGS. 7A-B Depict front views of the second embodiment within the well bore.

(8) FIG. 8 Depicts a cutaway end view of a prior art stabilizer.

DESCRIPTION OF THE INVENTION

(9) One way to maximize both contact area and flow area of the stabilizer is to spiral the stabilizing structures. However, the suitability of the flow area is often judged by end users by looking for an open line-of-sight path through the features. A spiral that is too long or twists too tightly (which would not provide an open line-of-sight path) is believed to encourage the buildup of cuttings and will result in blockage of the flow area.

(10) As shown in FIG. 1, to satisfy both 360° contact and line-of-sight flow path requirements stabilizer 100 utilizes two stabilizer sections or lobes 105A and 105B divided by a plenum 110 that interrupts the stabilizing features. The features on the back lobe 105A are angularly offset from the front lobe 105B, and in this way 360° contact is still achieved. For example, as can be seen in FIG. 2, looking down the drill string, the front lobe 105A and back lobe 105B combine to have 360° contact. Additionally, plenum 110 effectively interrupts the flow restrictions caused by lobes 105A and 105B, so the stabilizer 100 operates with lobes 105A and 105B that both satisfy the line-of-sight requirement, as shown in FIG. 4. Thus, while together lobes 105A and 105B do not satisfy the line-of-sight requirement (as shown in FIG. 2), lobes 105A and 105B individually satisfy the line-of-sight requirement (as shown in FIG. 4) and, in combination with plenum 110, achieve the desired flow of cuttings and prevent blockage of the flow area without limiting the contact of stabilizer 100 with the well bore.

(11) Preferably lobes 105A and 105B are identical. However, lobes 105A and 105B may be similar or different. Lobes 105A and 105B preferably have 2, 3, 4, 5, 6, or more spiraled protrusions. The protrusions on each lobe may spiral in the same direction or opposite directions. Preferably, the protrusions are equally spaced about the drill string. However, the protrusions may be eccentric or have another distribution. Between each protrusion is preferably a gap to allow the flow of drilling fluid and cuttings. At least a portion of the protrusions have cutters 115 extending from them. Cutters 115 clean up roughness in the well bore as the tool moves by, and also ensure the bore will have the proper fit against the stabilizing features. Preferably, cutters 115 cover at least a portion of each protrusion. However, cutters 115 may cover all of each protrusion. Preferably, cutters 115 are positioned so that the cutting face is tangential to the drill string. Cutters 115 are preferably polycrystalline diamond compact (PDC) surfaces. However, the cutters may be another material.

(12) A second embodiment of the invention is directed to a stabilizer 500 with two eccentric rollers 550A and 550B. To keep rollers 550A and 550B in contact with the well bore 560, as shown in FIG. 6, while not getting stuck within the well bore 560, rollers 550A and 550B are offset axially so stabilizer 500 can fit through tight spots by twisting/flexing out of axial alignment with the well bore 560. For example, as shown in FIG. 6, the axis 555 of stabilizer 500 may be at an angle to the axis 561 of well bore 560 while stabilizer 500 is in use.

(13) Furthermore, as can be seen in FIGS. 7A and 7B, the pass-through diameter 565 of stabilizer 500, which can be seen looking directly down the axis 555 of stabilizer 500, is smaller than the gauge diameter 570 of stabilizer 500, which can be seen looking directly down the axis 561 of well bore 560. Thus, stabilizer 500 can fit through a well bore 560 that is narrower than the gauge diameter of stabilizer 500.

(14) Preferably, each roller or stabilizing element 550A and 550B is eccentrically positioned such that the axis, 552A and 552B, of the roller 550A, 550B, respectively, is offset a first fixed distance 553A and a second fixed distance 553B, respectively, from the axis of stabilizer 500. Preferably the eccentricity of each roller is diametrically opposed about stabilizer 500 from the other roller. However, in other embodiments, the eccentricity of each roller may be at a different angle from the other roller. For example, the rollers may be 90°, 45°, 135°, or another angle apart. While two rollers a shown, in some embodiment, more than 2 rollers are employed at various positions. In embodiments where large rollers are not possible, two or more small eccentric rollers may be employed. In other embodiments where rollers are not possible, two or more eccentric wear pads may be used instead. Rollers 550A and 550B and the associated bearings are preferably large compared to traditional roller stabilizers (see FIG. 8). For example, the rollers of the instant application maybe have an outer diameter of 10″, 11″, 11.125″, 12″, or 13″ and the bearing surface of the rollers may have an inner diameter of 8″, 9″, 9.15″, 10″ or 11″. Preferably, the outer diameter of rollers 550A and 550B is 100%, 110%, 120%, 130%, or 140% of the drill string diameter, and the inner diameter (bearing surface) of rollers 550A and 550B is 90%, 95%, 99%, 105%, or 110% of the drill string diameter. With the larger size of the rollers and bearings compared to existing rollers and bearings, the bearings preferably have greater longevity, extending the intervals between repairs compared to traditional roller stabilizers' repair intervals.

(15) It is contemplated that aspects of any embodiment described herein can be employed in any other embodiment described herein. Furthermore, embodiments can be combined in any orientation. Other embodiments and uses of the invention will be apparent to those skilled in the art from consideration of the specification and practice of the invention disclosed herein. All references cited herein, including all publications, U.S. and foreign patents and patent applications, are specifically and entirely incorporated by reference. The term comprising, where ever used, is intended to include the terms consisting and consisting essentially of. Furthermore, the terms comprising, including, and containing are not intended to be limiting. It is intended that the specification and examples be considered exemplary only with the true scope and spirit of the invention indicated by the following claims.