POSITIONING CONTACT SURFACE WITH A RADIAL EXTENSION THAT DECREASES FOR A DIRECTIONAL DRILLING ASSEMBLY

Abstract

A downhole assembly for a directional drilling apparatus is provided. The downhole assembly includes at least one positioning element. The positioning element has a first radial extension when the downhole assembly is drilling a wellbore. When the downhole assembly inclination is greater than a predetermined amount, such as when the downhole assembly is horizontal, the positioning element has a second radial extension that is less than the first radial extension.

Description

CROSS-REFERENCE TO RELATED APPLICATION(S)

The present application is cross-referenced to U.S. patent application Ser. No. 15/667,704 Method, Apparatus By Method, And Apparatus Of Guidance Positioning Members For Directional Drilling, filed Aug. 3, 2017 the disclosure of which is incorporated herein as if set out in full. The present application is cross-referenced with U.S. patent application Ser. No. 15/808,798 Bottom Hole Assemblies For Directional Drilling, filed Nov. 9, 2017, the disclosure of which is incorporated as if set out in full.

TECHNICAL FIELD

The technology of the present application relates to improved bottom hole assemblies (BHAs) and stabilizers for directional drilling.

BACKGROUND

As has been disclosed and described in prior applications made by the applicant of the current technology the contact points of directional drilling assemblies with the borehole wall define and in large part control the directional behavior, and build and turn capabilities of a given assembly.

A key aspect of directional drilling which is well known to those skilled in the art is the difficulty of making the initial kick off into a build curve. A build curve can take many configurations but as a general proposition it is meant to turn the wellbore from vertical to horizontal. A typical architecture for a horizontal well will include a build length of about 900 feet and a buildup rate (BUR) of 10 degrees per 100 drilled feet. In some instances as a curve is built and gains angle towards horizontal the sensitivity, or ability of a given assembly to build angle increases. One explanation for this phenomenon is that prior to about 45 degrees of build the contact points obtain less “bite” into the borehole wall to provide build leverage to the system. Increasingly as the build goes beyond 45 degrees a given assembly becomes more aggressive in building angle. It can be considered to be more sensitive and reactive in slide mode drilling.

This increased sensitivity becomes of significant concern if the same assembly is pressed forward into the lateral section. The oversensitivity of the system in response to slide correction runs can create extensive tortuosity resulting in increased torque, drag, and ultimately a reduction in ultimate lateral wellbore length. Frequently this problem is addressed by switching out assemblies after the curve has been built, costing the operator an additional trip, in many cases solely to replace the build assembly with a less aggressive assembly for the lateral. In many instances the outer diameters of the stabilizers used in the replacement assembly are reduced, by between an ⅛ inch in diameter and 1 inch in diameter (depending on nominal hole diameter). This is done to reduce the torque and drag experienced in the lateral section, but provides a sub-optimum stabilization in the lateral section.

What is needed is a directional bottomhole assembly which is capable of aggressively building angle in the upper curve and then modifies to a less aggressive assembly in the lower curve or lateral section of the wellbore.

BRIEF SUMMARY

As has been laid out in the cross-referenced applications, the current applicants have identified the significant impact the radial extension of a scribe side above bend positioning element has on the ultimate build characteristics of a directional BHA. To a lesser extent, but also significant in their influence on build are the radial extensions of a bend side near bit positioning element and/or a bend side kick pad if either or both are employed.

Prior art has given paramount importance to the bend angle as the overwhelmingly determinant attribute of a directional assembly's build capabilities in slide mode. Extensive geometric modeling performed by the applicants and verified by field test have demonstrated that reduced radial extensions of a scribe side above bend element and (if any) bend side positioning or kick pad elements act to reduce the build rate (sensitivity) in slide mode, even with an aggressive bend angle.

The technologies of the present application teach methods of obtaining the goal of effectively making the curve and the lateral with the same assembly in a single run by reducing the radial extension of the contacting elements over the course of the curve, or at the inception or first several hundred feet of the lateral section.

The contacting elements of the current technology are abradeable/erodible, dissolvable, or mechanically depressible to provide outer radial extensions that are reduced over the course of the build or at the commencement of the lateral section.

One version of abradeable/erodible contact surfaces are manufactured entirely or substantially from brass, tin, low hardness steel or other relatively soft metal or metal alloy. The soft metal material is mounted on the parent BHA positioning elements through known manufacturing processes such as casting, brazing, mechanical attachment, or adhesives. The soft metal material is sound enough early in the run to provide the leverage required for aggressive build rates but by wearing down over the course of the curve section or into the lateral section reduces the radial extension of the contact surfaces to yield a less aggressive, less sensitive directional assembly. Typically an intervening hard material, such as hard facing or embedded tungsten carbide inserts is deployed under the soft material on the steel of the parent BHA positioning body. This intervening hard material effectively limits the continuation of wear after the softer outer material has worn away. In the case of drilling through formations that are harder and more abrasive the soft metal sheathing of the contact surfaces can be formed with inclusions of harder material to reduce the rate of wear and abrasion. Candidate hard material inclusions may be but are not limited to: steel, tungsten carbide, natural diamond, synthetic diamond, or any other materials or combinations of materials known in the art.

Phenolic materials are an alternative material for abradeable/erodible contact surfaces. As with soft metal sheathing materials phenolic may be formed with known manufacturing techniques and mounted to the parent BHA positioning elements mechanically, or by adhesives as are known in the art. Harder material inclusions may be deployed in the phenolic to resist accelerated wear in more abrasive drilling applications. As with the soft metal noted above an intervening hard material such as hard facing or tungsten carbide inserts typically underlays the phenolic to limit continued wear after the phenolic has worn away.

Dissolvable materials are also known in the art. Reference is made to U.S. Pat. No. 9,856,411 as an example of the downhole use of dissolvable materials. The subject patent discusses specifically a degradable thermoset polymer material for use in frac plug applications. This or a similar material may be used for the sheathing material of the contact elements of the BHA. When used in this way the thermoset materials are attacked with fluid that reacts with the thermoset and dissolves the thermoset material. By way of a non-limiting example, a slug of high salt content fluid in the drilling fluid column to dissolve the sheathing and thereby reduce the radial extension of the contact surfaces. While a thermoset material that is dissolves in a high salt content fluid is described, other composites and fluid additives are possible. Of note is the fact that different formulations of dissolvable material will dissolve at different rates or in response to variations in fluid make up. In practicing the technology of this application dissolvable formulations are chosen which will survive substantially intact in the early part of the drilling. Another optional applicable feature of dissolvable material formulations of the present application is the use of a more slowly dissolvable shell as an outer surface of the dissolvable with a more quickly dissolving formulation at the core of the dissolvable component. This approach may better resist dissolving for a substantial or all of the curve section of the well, and then quickly dissolve and evacuate later in the run.

As with soft metal or phenolic materials if the formations to be drilled are abrasive and will wear the polymer material too quickly then the polymer may be reinforced with inclusions of harder material as listed earlier. Also, as with soft metals, an underlying hard material layer limits ongoing wear after the outer dissolvable layer has dissolved away.

Dissolvable materials may also be used as an intervening material between the parent BHA positioning element base and an outer hard material facing. Once the curve has been made or nearly made and the drilling is ready to enter or has entered the lateral section a slug of high salt content drilling fluid is pumped down to dissolve the intervening thermoset polymer material. The outer metal sheath can then be depressed along slide, guide, or hinged surfaces as known in the art to effectively reduce the radial extension of the contact surfaces.

Another alternative is to have the outer contact surfaces set with caged rotating balls in contact with the formation. The balls are under laid by wearable or dissolvable material. Over the course of the run the underlying support for the ball wears down reducing the radial extension of the ball. If a dissolvable material is used as before a slug of high salt fluid may be used to dissolve the underlying support to reduce the radial extension of the contact surfaces when the wellbore has reached the end of the curve or the beginning of the lateral section.

In the embodiments where a harder surface or ball are under laid by a dissolvable or wear element the tool may be designed to allow for the replacement of the underlying wear element or dissolvable to prepare the tool for use in another well.

In another embodiment, for use in well operations employing either water based or oil based drilling fluids, an outer wear resistant facing is deployed on a tensioned strip of fluid, such as water or oil, swellable elastomer. The strip is anchored end to end or side to side above a depression gap in the tool body. The tensioning of the elastomer maintains the outer hard surface at the designed diameter early in the run. As the elastomer swells during the course of the run, or when activated by an appropriate fluid additive, it elongates, relaxing the tension and reducing the diameter of the deployed hard surface. An additional feature of this embodiment includes dissolvable supporting structures between the tool body and the tensioned rubber strip. These structures supply additional support to the tensioned strip early in the run and dissolve over the course of the run allowing the swollen strip to depress, decreasing the outer diameter of the contact surface.

In an alternative embodiment a hard outer surface is supported in its desired initial position by a ball in an angled channel below the hard surface. The ball is held in place by a dissolvable material. Once the retaining dissolvable material dissolves away the ball is free to move along the channel in a reduced radial deployment allowing the outer hard surface to depress. In the case of the above bend positioning element the movement of the ball to a reduced radial deployment is assisted by gravity in slide mode when the tool is in the lower curve or lateral sections of the wellbore.

In an alternative embodiment a hard outer surface is supported by a bladder containing an incompressible fluid. An orifice in the bladder is sealed with a dissolvable material. Over the course of the tool run the drilling fluid attacks the dissolvable seal, eventually breaking the seal and allowing the contained incompressible fluid to evacuate the bladder, allowing for the depression of the hard outer surface.

In an alternative embodiment a hard outer surface is supported in its desired initial position by a piston in a piston housing below the hard surface. The piston is connected to and actuated by a sensor and battery assembly. The sensor may be an inclinometer or a revolution counter. In the case of the inclinometer, once the BHA achieves (or exceeds) a predefined inclination, such as, for example, a 90 degree inclination in some embodiments or a 45 degree inclination in other embodiments, a signal from the sensor and battery pack causes the retraction of the piston allowing the outer hard surface to retract. In the case of the revolution counter once the counter has sensed a predetermined number of revolutions of the motor the sensor and battery pack causes the retraction of the piston. In both cases the sensor pack may be armed at surface such as by a key or a magnetic arming device when the tool is being run into the hole.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a cross section view of an above bend positioning/stabilizer element with a soft metal wearable outer pad mounted on a blade.

FIG. 2 shows a cross section view of an above bend positioning/stabilizer element with harder material inclusions in a soft metal wearable outer pad mounted on a blade.

FIG. 3 shows a cross section view of an above bend positioning/stabilizer element with a dissolvable outer pad mounted on a blade.

FIG. 4a shows a cross section view of an above bend positioning/stabilizer element with an outer hard material element underlain by dissolvable material.

FIG. 4b shows a cross section view of an above bend positioning/stabilizer element with an outer hard material element depressed into a lower position.

FIG. 5a shows a cross section view of an above bend positioning/stabilizer element with a caged hard metal ball underlain by a wearable or dissolvable material.

FIG. 5b shows a cross section view of an above bend positioning/stabilizer element with a caged hard metal ball depressed into a lower position.

FIG. 6a shows a cross section view of an above bend positioning/stabilizer element with a swellable rubber tensioner supporting a hard outer surfacing material.

FIG. 6b shows a cross section view of an above bend positioning/stabilizer element with a now swollen and depressed rubber tensioner supporting a hard outer surfacing material.

FIG. 7a shows a cross section view of an above bend positioning/stabilizer element with a hinged hard metal surface underlain by a channeled hard metal ball held in place by a dissolvable insert.

FIG. 7b shows a cross section view of an above bend positioning/stabilizer element with a hinged hard metal surface now depressed following the dissolving of the insert and the movement of the hard metal ball down the channel.

FIG. 8a shows a cross section view of an above bend positioning/stabilizer element with a hard metal surface underlain by a fluid filled bladder sealed with a dissolvable stopper.

FIG. 8b shows a cross section view of an above bend positioning/stabilizer element with a hard metal surface underlain by a bladder now unsealed and depressed.

FIG. 9a shows a cross section view of an above bend positioning/stabilizer element with a hinged hard metal surface underlain by a deployed piston rod held in place by a piston housing connected to a sensor and battery pack.

FIG. 9b shows a cross section view of an above bend positioning/stabilizer element with a hinged hard metal surface now depressed by the retraction of the piston rod in response to a signal from the sensor and battery pack.

DETAILED DESCRIPTION

FIG. 1 shows a cross section view of an above bend positioning/stabilizer element 100 (generically positioning element 100) with a soft metal wearable outer pad 103 mounted on a blade 102 and underlain by a hard material surface 106. The parent housing body, which may be the housing of a down hole assembly or bottom hole assembly (BHA) is shown at 101. As can be appreciated, the blade 102 with both the wearable outer pad 103 and hard material surface 106 has a first radial extension from the parent housing body 101. When the wearable outer pad 103 wears, due to friction for example, the blade 102 with the hard material surface 106 will have a second radial extension that is less than the first radial extension. Each of the embodiments described herein provides a positioning/stabilizer elements that have first radial extensions that are greater than the second radial extension. The hard material surface 106 may be referred to as a radially inner portion and the wearable outer pad 103 may be referred to as a removable radially outer portion.

FIG. 2 shows a cross section view of an above bend positioning/stabilizer element 200 with a soft metal wearable outer pad 203 mounted on a blade 202 and underlain by a hard material surface 206. In this embodiment soft metal wearable outer pad 203 includes hard material inclusions 204, sometimes referred to as interstitial hard material 204. The parent housing body is shown at 201.

FIG. 3 shows a cross section view of an above bend positioning/stabilizer element 300 with a dissolvable outer pad 305 mounted on a blade 302 and underlain by a hard material surface 306. The parent housing body is shown at 301. In an alternative embodiment (not shown) dissolvable outer pad 305 may be reinforced with harder material.

FIG. 4a shows a cross section view of an above bend positioning/stabilizer element 400a with an outer hard material element 406a underlain by dissolvable material 405 mounted on blade 402. Depression areas 407 are void and will allow hard metal element 406a to depress once dissolvable material 405 has dissolved. The parent housing body is shown at 401.

FIG. 4b shows a cross section view of an above bend positioning/stabilizer element 400b with an outer hard material element 406b now depressed into blade 402 following the dissolving of the dissolving material 405 previously shown in FIG. 4a. The parent housing body is shown at 401.

FIG. 5a shows a cross section view of an above bend positioning/stabilizer element 500a with a caged hard metal ball 509a held in cage 508 in blade 502 and underlain by a wearable or dissolvable material 505. The parent housing body is shown at 501.

FIG. 5b shows a cross section view of an above bend positioning/stabilizer element 500b with a caged hard metal ball 509b now depressed into blade 502 following the wear or dissolving of element 505 shown in FIG. 5a. The parent housing body is shown at 501.

FIG. 6a shows a cross section view of an above bend positioning/stabilizer element 600a with a swellable tensioner 611a anchored to blade 602 at anchor points 610. The swellable tensioner 611a supports a hard outer surfacing material 606a in a radially extended position. The parent housing body is shown at 601. The swellable material for the swellable tensioner 611a may comprise a number of swellable materials such as, for example, natural rubber, synthetic rubber, hydrogels, to name but a few materials.

FIG. 6b shows a cross section view of an above bend positioning/stabilizer element 600b with a now swollen and depressed swellable tensioner 600b anchored to blade 602 at anchor points 610. Relaxed swellable tensioner 611b maintains attachment with hard outer surfacing material 606b now in a relaxed position. The parent housing is shown at 601.

FIG. 7a shows a cross section view of an above bend positioning/stabilizer element 700a with a hinged hard metal surface 706a underlain by a channeled hard metal ball 709a held in place by a dissolvable insert 705 in channel 711 all deployed in or on blade 702. In FIG. 700a hinged hard metal surface 706a is shown in a radially extended position anchored at hinge 712. The parent housing is shown at 701.

FIG. 7b shows a cross section view of an above bend positioning/stabilizer element 700b with a hinged hard metal surface 706b now depressed following the dissolving of the insert 705 and the movement of the hard metal ball 709b down the channel 711. The parent housing is shown at 701.

FIG. 8a shows a cross section view of an above bend positioning/stabilizer element 800a with a hard metal surface 806a underlain by a fluid filled bladder 813a sealed with a dissolvable stopper 805. The fluid in the bladder may be free of components such as salt which would attack the dissolvable stopper 805. The bladder 813a is anchored to blade 802 at points 810. The parent housing is shown at 801.

FIG. 8b shows a cross section view of an above bend positioning/stabilizer element 800b with a hard metal surface 806b underlain by bladder 813b now unsealed, deflated and depressed. The deflated bladder 813b is anchored to blade 802 at points 810. The parent housing is shown at 801.

FIG. 9a shows a cross section view of an above bend positioning/stabilizer element 900a with a hinged hard metal surface 906a underlain by a deployed piston rod 909a held in place by a piston housing 905 connected to a sensor and battery pack 913 through connector 914. Radially extended hard metal surface 906a is attached to blade 902 at hinge 912. The parent housing is shown at 901.

FIG. 9b shows a cross section view of an above bend positioning/stabilizer element 900b with a hinged hard metal surface 906b now depressed by the retraction of the piston rod 909b in response to a signal from the sensor and battery pack 913 sent through connector 914. Radially retracted hard metal surface 906b is attached to blade 902 at hinge 912. The parent housing is shown at 901.

Although the embodiments shown in the Figures refer to above bend positioning/stabilizer elements the technologies of this application may equally be applied to below bend positioning/stabilizer elements, kick pad elements, or string stabilizers.

Although the embodiments shown in the Figures show a single blade in cross section the technologies of this application may equally be applied to positioning/stabilizer elements with two or more blades.

Although specific embodiments are disclosed in the Figures those skilled in the art will readily see that the features of the technologies disclosed in this application may be adapted from one embodiment to another. For instance (not shown) the sensor and battery pack and piston assembly shown in FIGS. 9a and 9b could be deployed in the depressions 407 and blade 402 of FIG. 4a with appropriate modifications to hard metal surface 406a.

Although the technologies of the present application have been described with reference to specific embodiments, these descriptions are not meant to be construed in a limiting sense. Various modifications of the disclosed embodiments, as well as alternative embodiments of the technologies will become apparent to persons skilled in the art upon reference to the description of the technologies. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the technologies. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirt and equivalent constructions as set forth in the appended claims. It is therefore contemplated that the claims will cover any such modifications or embodiments that will fall within the scope of the technology.

Claims

1. A downhole apparatus comprising:

a housing configured and sized to fit within a wellbore, the housing including a drilling assembly at a bottom portion of the housing and having at least a first bend located above the drilling assembly;

at least one positioning element coupled to the housing, the at least one positioning element comprising: a blade wherein the blade comprises: at least a radially inner portion and at least a removable radially outer portion coupled to the radially inner portion; and wherein the blade has a first radial extension that includes the radially inner portion and the removable radially outer portion, wherein the blade has a second radial extension that includes the radially inner portion when the removable radially outer portion is removed such that the second radial extension is less than the first radial extension.

2. The downhole apparatus of claim 1 wherein the at least one positioning element is coupled to the housing such that the first bend is located between the at least one positioning element and the drilling assembly.

3. The downhole apparatus of claim 1 wherein the blade is a metal and the removable radially outer portion is a wearable material.

4. The downhole apparatus of claim 3 wherein the wearable material comprises a material that is softer than a material comprising the radially inner portion.

5. The downhole apparatus of claim 4 wherein the wearable material selected from the group of material consisting of: a metal softer than the material of the first portion, a phenolic material softer than the material of the first portion, or a combination thereof.

6. The downhole apparatus of claim 1 wherein the removable radially outer portion comprises interstitial hard material.

7. The downhole apparatus of claim 1 wherein the removable radially outer portion is a dissolvable material.

8. The downhole apparatus of claim 7 wherein the dissolvable material is configured to dissolve based on a composition of a drilling fluid.

9. The downhole apparatus of claim 8 wherein the dissolvable material is a polymer material that dissolves in the presence of saltwater.

10. A downhole apparatus comprising:

a housing configured and sized to fit within a wellbore, the housing including a drilling assembly at a bottom portion of the housing and having at least a first bend located above the drilling assembly;

at least one positioning element coupled to the housing, the at least one positioning element comprising: a blade wherein the blade comprises: at least a removable radially inner portion and at least a radially outer portion coupled to the removable radially inner portion; and wherein the blade has a first radial extension that includes the removable radially inner portion and the radially outer portion, wherein the blade has a second radial extension that includes the radially outer portion when the removable radially inner portion is removed such that the second radial extension is less than the first radial extension.

11. The downhole apparatus of claim 10 wherein the removable radially inner portion supports the radially outer portion until it is removed.

12. The downhole apparatus of claim 10 wherein the removable radially inner portion comprises a dissolvable material.

13. The downhole apparatus of claim 12 wherein the dissolvable material is a polymer.

14. The downhole apparatus of claim 13 wherein the polymer is configured to dissolve when salt is present in a drilling fluid.

15. The downhole apparatus of claim 10 wherein the radially outer portion comprises a hard metal.

16. The downhole apparatus of claim 10 wherein the radially inner removable portion comprises a piston operably coupled to a piston driver wherein the piston has an extended position and a retracted position such that the radially inner removable portion is removed when the piston is in the retracted position.

17. The downhole apparatus of claim 12 wherein the radially inner portion comprises a bladder and the dissolvable material comprises a seal for the bladder such that the bladder is filled with a fluid when the dissolvable material is not dissolved and the bladder is empty when the dissolvable material is dissolved.

18. A downhole apparatus comprising:

a housing configured and sized to fit within a wellbore, the housing including a drilling assembly at a bottom portion of the housing and having at least a first bend located above the drilling assembly;

at least one positioning element coupled to the housing, the at least one positioning element comprising: a movable first portion; and a piston coupled to the first portion wherein the piston has an extended position and a retracted position, wherein the movable first portion has a first radial extension when the piston is in the extended position and the movable first portion has a second radial extension less than the first radial extension when the piston is in the retracted position.

19. The downhole apparatus of claim 18 comprising a sensor to sense an inclination of the housing such that when the sensor detects that the inclination of the housing is greater than a predetermined orientation, the piston is moved from the extended position to the retracted position.