US20170204700A1

US20170204700A1 - Wellbore tool and method

Info

Publication number: US20170204700A1
Application number: US15/263,990
Authority: US
Inventors: John Hughes; James Wilburn Schmidt; Shane D'Arcy
Original assignee: RESOURCE COMPLETION SYSTEMS Inc
Current assignee: RESOURCE COMPLETION SYSTEMS Inc; Wellboss Co Inc
Priority date: 2014-03-20
Filing date: 2015-03-05
Publication date: 2017-07-20
Also published as: WO2015139111A1; WO2015139111A8; CA2993296A1

Abstract

A wellbore tool includes a seat within the tool's inner diameter. At least the seating surface of the seat, which is that surface exposed within the tool, is formed of a dissolvable material. The tool also includes a support area on the tool body, on which the seat is mounted. The support area is formed of a material stronger than the dissolvable material.

Description

FIELD

The invention relates to a method for completing a wellbore and a wellbore tool.

BACKGROUND

A ball, or another form of plug, may be employed to actuate a wellbore tool and/or to divert fluid flows by landing the ball on a seat (often called a ball seat) in the wellbore tool, which creates a seal in the tool's inner diameter. Since the ball creates a seal in the inner diameter, fluid can be diverted and/or fluid pressure can be built up above the ball and seat to create a hydraulic force.
In multi-stage fracturing, for example, a wellbore string (often called a string or a casing) can include valve tools actuated by landing a ball in a seat. After the ball lands on the seat, applied pressure causes the ball and seat to shift a valve sleeve which exposes ports in the string. These ports provide a means of establishing communication between formation and the inner diameter of the string. Stimulation fluid can then be pumped through the ports.
When the fracturing treatment is completed, the seats remain in the string. In order to remove the ball seats, they must be milled up or retrieved. Regardless of the method of removal is employed, intervention with coiled tubing is necessary. This requires a cost in terms of time and equipment.

SUMMARY

In accordance with a broad aspect of the present invention, there is provided a wellbore tool comprising: a tool body including a tubular wall and an inner diameter; a seat within the inner diameter, the seat including a bore with an inner diameter that tapers through a seating surface, the seat also including a backside surface opposite the bore, the seat including the seating surface being formed of a dissolvable material; and a support area on the tool body, the seat mounted on the support area, the support area formed of a material stronger than the dissolvable material.
In accordance with another broad aspect, there is provided a wellbore frac valve tool comprising: a tubular body including a wall, an upper end, a lower end and an inner bore extending from the upper end to the lower end, the inner bore having an inner diameter; a port through the wall; a sleeve valve in the inner bore and having a inner facing surface exposed in the inner bore, the sleeve valve moveable from a port-closed position over the port and a port-open position retracted from the port; a support area on the inner facing surface of the sleeve; and a ball seat in the support area and connected for movement with the sleeve, the ball seat including a portion exposed in the bore having a diameter less than the inner diameter and the portion is formed of dissolvable material.
Also provided is a method for completing a wellbore, the method comprising: landing a ball on a ball seat to actuate a frac valve tool to open ports to the formation; treating the formation; and opening up the frac valve tool to a full bore diameter by providing time for the ball seat to dissolve.
It is to be understood that other aspects of the present invention will become readily apparent to those skilled in the art from the following detailed description, wherein various embodiments of the invention are shown and described by way of illustration. As will be realized, the invention is capable for other and different embodiments and its several details are capable of modification in various other respects, all without departing from the spirit and scope of the present invention. Accordingly the drawings and detailed description are to be regarded as illustrative in nature and not as restrictive.

BRIEF DESCRIPTION OF THE DRAWINGS

A further, detailed, description of the invention, briefly described above, will follow by reference to the following drawings of specific embodiments of the invention. The drawings depict only typical embodiments of the invention and are therefore not to be considered limiting of its scope. In the drawings:

FIG. 1 is a schematic, sectional view along a long axis of a wellbore string;

FIG. 2A is a schematic, sectional view along a long axis of a wellbore tool in run-in condition;

FIG. 2B is a view of the tool of FIG. 2A after use;

FIG. 3 is a schematic, section view along a long axis of a further embodiment of a wellbore tool in run-in condition; and

FIG. 4 is a process diagram of a method of completing a wellbore.

The drawing is not necessarily to scale and in some instances proportions may have been exaggerated in order more clearly to depict certain features.

DETAILED DESCRIPTION OF VARIOUS EMBODIMENTS

The description that follows and the embodiments described therein are provided by way of illustration of an example, or examples, of particular embodiments of the principles of various aspects of the present invention. These examples are provided for the purposes of explanation, and not of limitation, of those principles and of the invention in its various aspects.
A wellbore tool and method for wellbore completion have been invented. The wellbore tool includes a seat that is removable without intervention. As for the method, it permits the establishment of a full bore through a wellbore string that previously had one or more ball seats therein, without intervention required to remove the one or more ball seats.
In particular, a ball seat has been invented that relies on deterioration of the seat material that projects into the inner diameter, such that the projecting portions of the seat dissolve on their own and intervention is not required for removal of the seat. The ball seat includes a dissolvable material that breaks down by reactive processes but which is supported such that it can withstand the forces generated during use of the seat, for example when a ball lands on the seat.
While the seat can be employed in various tools for fluid diversion and/or tool actuation, FIGS. 1 and 2 shows one embodiment of a seat in a wellbore tool 10, which is in the form of a fracing valve.
With reference to FIG. 1, one embodiment of a wellbore string 12 is shown. This figure shows the string, commonly also called a liner or a casing, with a fracing valve tool 10 installed therein. String 12 is shown installed in a wellbore 4. FIG. 2A shows a fracing valve tool 10 in a run-in condition, which is the condition the tool is in during run-in of the string.
Wellbore tubular string 12 and wellbore tool 10 have features that permit operation by a ball 24 landing on a seat 22 in the tool. Herein, actuation opens ports 23 to permit selective fluid treatment of wellbore 4 in which the string is positioned.
String 12 may be installed in wellbore 4 and the string then provides a conduit through which the wellbore may be selectively treated and, thereafter, through which produced fluids may exit the wellbore. The string may be installed in various ways in a cased wellbore or in an open hole wellbore, wherein the formation is exposed and forms wellbore wall 4a, as shown.
Fluid treatment ports 23 extend through the tool's wall, which is also the wall of the string, for example, to provide fluid communication from the surface of the string's inner wall 12 a to the string's outer surface 12 b facing wellbore wall 4 a.
Tool 10 is formed to be secured into the string and to form a portion thereof. In particular, the tool includes a tubular body 14, which can be secured to adjacent portions of the string and forms a portion of the string wall.
The tubular body may include an open upper end 14 a and an open lower end 14 b and a bore 14 c extending between the ends. In this embodiment, these ends 14 a, 14 b are formed, for example as by threading, for connection into string 12. Bore 14 c has an inner diameter ID that is substantially a full bore diameter, which is generally the same as the diameter measured across inner wall 12 a of string 12.
Tool 10, being a frac valve tool further includes a sleeve valve 16 within the tubular wall. The sleeve valve is positioned in an annular recess 18 in the wall of the tubular body. Sleeve valve 16 normally covers ports 23, as shown, but can be moved axially along the annular recess to expose and thereby open ports 23. Sleeve valve 16 is normally held in a position covering ports by a releasable lock such as shear pins 25. However, the releasable lock may be overcome by application of sufficient force to move the sleeve valve to a port-open position, wherein ports 23 are exposed to the inner bore of the tool.
Sleeve valve 16 has a tubular form, wherein a bore 20 extends through the sleeve valve from its upper end 16 a to its lower end 16 b such that a fluid passage is provided through the sleeve valve and the tool. The bore has defined therein a seat 22. As will be appreciated, a seat 22 is a constriction that projects into the inner diameter of a bore and has a seating surface 22 a to catch a ball attempting to pass through the bore. The seat defines a diameter D thereacross that is reduced relative to the inner diameter ID of other portions of bore 20 and bore 14 c. In particular, the seat may be formed frustoconically at seating surface 22 a leading to the minimum diameter across seat 22. The seat accepts and forms a seal with ball 24 or other plug form. The ball used with tool 10 is sized to pass through the string uphole of tool 10 and to enter bore 20. However, the ball is selected to have a diameter too large to pass through the seat 22.
Thus, ball 24 can be introduced to the string to land in seat 22 of the tool when it is desired to plug bore 20, and in this embodiment, to thereby hydraulically drive sleeve valve 16 to open ports 23 and to divert fluid to ports 23.
At least some portions of the seat project into the inner diameter of the bore and have diameters thereacross that are less than the full bore diameter ID. While previously, this projecting seat material, which created a diameter constriction in the inner bore, was removed by intervention, such as by milling out or by retrieval, the present seat includes projecting portions formed of dissolvable material. Dissolvable material is removable by deterioration in wellbore conditions to achieve a full bore diameter across the area in which the seat was positioned (FIG. 2B). For example, the dissolvable material can dissolve by contact with naturally occurring or specifically introduced wellbore fluids. Herein the terms dissolve, deteriorate, degrade, disintegrate and break down are interchangeable and indicate that the material is removed automatically, over time due to contact with wellbore fluids.
The dissolvable material may be selected from various known dissolvable materials for wellbore operations. Some dissolvable materials include polymers such as polyvinyl alcohol based polymers, polylactide polymer, polyglycolic acid, etc., alloys such as of aluminum or magnesium, compacts such as of non-dissolvable metal powder bound by dissolvable binders. Dissolvable materials may be reactive to one or more of water, drilling fluid (water-based or hydrocarbon-based), acid, solvent, petroleum, natural gas, etc. and they dissolve over a time that is less than the breakdown time of materials used in wellbore structures that are desired to be substantially permanent, such as the material used for tubular body 14 and sleeve valve 16. Dissolvable materials break down automatically and since an exposed member formed of dissolvable material may begin immediately to react with wellbore fluids, it may be desirable to select a material that remains substantially intact for long enough to be run in hole and to serve as a seat, before it dissolves to the point of rendering the seat inoperative. In one embodiment, it is desirable for the seat to maintain its integrity for about one to two weeks and then to be completely dissolved to open the tubing string to full bore diameter within a year. Materials with predictable dissolution rates are known.
In one embodiment, only portions of the seat that project to define a diameter D less than the full bore diameter are formed of dissolvable material, in another embodiment the entire seat is formed of dissolvable material. In some embodiments, even portions that do not project into the inner diameter may be formed of dissolvable material.
In a preferred embodiment, as illustrated in FIG. 3, a protective coating 40 may be applied to at least a portion of the seat 22 to isolate the dissolvable seat material from wellbore fluid until removal of the seat 22 is desired. The coating 40 allows the present tool 10 to be deployed in the wellbore 4 on the tubular string 12 at any time prior to stimulating the formation, without concern of the seat 22 prematurely deteriorating. In a further preferred embodiment, the coating 40 may be susceptible to wear from exposure to elements either naturally found or specifically introduced into the stimulation fluid when the formation is stimulated, leading to at least partial wearing away or removal of the coating 40 from the seat 22 during stimulation. Such elements in the stimulation fluid can be for example, sand or other abrasive components. The dissolvable seat material is thus exposed to wellbore fluids and removed by deterioration to achieve a full bore diameter across the area in which the seat 22 was positioned, as described earlier and illustrated by FIG. 2B. The coating 40 may be of any material well known in the art that can be applied to the seat 22 to add a layer of protection between the seat 22 and wellbore fluids. In one embodiment the coating 40 may be applied to the seat as a liquid that then dries to form the protective coating 40. In another embodiment, the coating 40 may be formed of a solid that is affixed or otherwise applied to an outer surface of the seat 22. In yet another embodiment, the protective coating 40 may be formed by building up the seat 22 with extra dissolvable seat material, said extra dissolvable seat material wearing way during stimulation and leading a remainder of the dissolvable seat material being removed by exposure to wellbore fluids, as described above.
Since dissolvable materials may be weak, the seat may be installed in a support area 30 to provide adequate strength to withstand the forces generated during landing of a ball on the seat as well as the forces that follow, which are generated by hydraulic pressures that develop while the ball remains in the seat. The support area is on the tool where the seat is to be mounted. In the illustrated embodiment, seat 22 is on sleeve valve 16 and support area 30 is on the sleeve valve. Support area 30 may either be formed in, as shown, or secured to the sleeve valve. Either way, support area 30 is formed of material that is stronger than the dissolvable material of the seat. Support area 30 may, for example, be formed of materials normally selected for durability in wellbore conditions and for parts that undergo stresses, such as cast iron or steel.
Support area 30 may (i) support the seat against radial forces and/or (ii) support the seat against axial forces.
For example, support area 30 may be formed to accommodate the radial strain generated by the ball pushing against the seat. The support area may, for example, substantially prevent damage caused by radial expansion of the seat when the ball pushes against the seat. Support area 30 may be formed to substantially follow the shape of the backside 22 b of the seat. For example, seat 22 may be formed as a cylindrical member with its backside formed as a circumferentially continuous (i.e. non segmented) cylinder and support area 30 may also be formed as a circumferentially continuous cylinder with an inner diameter substantially the same as the outer diameter of the backside 22 b. In the illustrated embodiment, for example, the backside of seat 22 tapers, for example is frustoconically formed, such that the outer diameter of the seat at its lower end is smaller than the outer diameter of the seat at its upper end and support area 30 is also frustoconically formed and has an inner diameter that tapers toward its lower end at the same rate as the taper on backside 22 b of the seat. Regardless, support area 30 is formed to substantially follow the backside shape of the seat so that the seat can be positioned with its backside close against the support area. Support area 30, thus, provides that seat 22 is unable to radially expand and, therefore, cannot fail by cracking or splitting due to hoop stress.
In addition or alternately, the support area may support the seat against damage due to axial forces. For example, the support area may include the above noted tapering in inner diameter from its upper end to its lower end such that the seat is restricted from being expelled downwardly when the ball lands and is hydraulically pressed downwardly on the seating surface 22 a. Alternately or in addition, the seat may include a backside projection 22 c that engages a stop wall 30 a in the support area. Stop wall 30 a faces upwardly toward the tool's upper end 14 a and projection 22 c catches on it, so that seat 22 cannot slide down toward lower end 14 b relative to the support area 30. In the illustrated embodiment, the projection is annular, projects radially outwardly from the seat and is positioned at an upper end of the seat. Also in the illustrated embodiment, stop wall 30 a is part of an annular groove 30 b that accommodates the projection between stop wall 30 a and an upper stop wall 30 c.
Support area 30 may include a lock nut-type arrangement, wherein a part may be threaded against projection 22 c to clamp the projection, and therefore the seat, in the support area and, in particular on the sleeve. For example, annular groove 30 b may be formed at a threaded connection 32 with one stop wall on either side of the threaded connection. Thus, stop wall 30 a may be threaded into selected but variable proximity to upper stop wall 30 c and projection 22 c can be positioned therebetween and clamped between the walls by threading up the connection 32. The lock nut-type arrangement anchors the seat into the support area and allows a preload to be applied to the seat to push it into the taper along support area 30, which, thereby, places backside surface 22 b of the seat into close contact with the support area.
In the illustrated embodiment, support area 30 is, as noted, on sleeve valve 16. Sleeve valve 16 is formed with an upper portion and a lower portion. The upper and lower portions are threaded together at connection 32 and thereby form the lock nut-type arrangement.
The support area may be formed to ensure a full bore diameter therethrough. In the illustrated embodiment, sleeve 16 resides in annular groove 18 and does not project into the bore 14 c in any way that limits the full bore diameter ID through the tool. The sleeve may, therefore, have an inner diameter that is no less than the full bore diameter and only seat 22, which is formed of dissolvable material, projects into the bore.
The sleeve valve is a complete cylindrical form and the seat is positioned within its bore 20. Removal of seat 22 by dissolution does not change the structure of the sleeve valve.
Once the sleeve valve has been shifted to the port-open position, it can be shifted back over the ports, if there is a desire to reclose the ports. This is true even after seat 22 is removed by dissolution. Sleeve valve 16 may include a lock to hold the sleeve in the open position. For example, a snap ring 33 may be carried on sleeve valve 16 that engages in a catch 34 in annular groove 18.
Seals 36 are positioned between the sleeve valve and body 14 to prevent leakage past the sleeve to the ports when sleeve valve 16 is closed.
A seal 38 may be provided between seat 22 and sleeve 16 to prevent fluid from passing between the parts. Seal 38 may be an o-ring, for example, that encircles the backside surface of the seat. Seal 38 therefore ensures that fluid can pass only through the bore of the seat and if that bore is sealed, as by a ball landed therein, fluid flow past the seat is stopped.
In use, a tool in which the seat is installed is run into a wellbore. With reference to FIG. 4, the seat is useful to accept and seal with a ball to divert fluids and/or to actuate the tool. Thereafter, the seat is removed automatically, over a reasonable time by dissolution to open the string in which the seat is installed to substantially a full bore diameter.
With respect to the tool of the presently illustrated embodiment, the tool is intended to be positioned in a string with the upper end connected to be closer to surface than the lower end and the bore 14 c in communication with the bore 12c of the string. The string, and therefore the tool, is run into a position in a wellbore so that the ports 23 may be adjacent a particular area of the wellbore. A ball 24 is introduced to the string and moves to land in the seating surface 22a of the seat 22. Pressure is then increased above ball 24 and seat 22. The ball and the seat together form a piston against which the fluid pressure may act to create a force against sleeve 16. Eventually, the shear pins are overcome and sleeve valve 16 moves down to open ports 23. Fluid can then be diverted through ports 23 to the wellbore to stimulate, for example fracture, the formation.
During this process, the seat, although formed of dissolvable material which may be weaker than usual sleeve and seat materials, is supported on its backside 22b by support area 30, which avoids splitting and failure of the seat. The seal 38 substantially prevents fluid from leaking between seat 22 and sleeve 16.
After the fracing process, with sufficient residence time, the wellbore fluids or introduced fluids automatically dissolve the seat portions that are made of dissolvable material to establish a full bore diameter through the tool (FIG. 2B). The sleeve valve remains in the tool and can be moved to re-close ports 23, if desired.
Ball 24 may remain downhole, may migrate back to surface with produced fluids or may be actively removed. Alternately, ball 24 may also be formed of a dissolvable material, if desired. In such an embodiment, both seat 22 and ball 24 are removed by dissolution.
The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments without departing from the spirit or scope of the invention. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article “a” or “an” is not intended to mean “one and only one” unless specifically so stated, but rather “one or more”. All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are known or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims.

Claims

1. A wellbore tool comprising: a tool body including a tubular wall and an inner bore; a seat formed of dissolvable material and positioned within the inner diameter, the seat including an upper end, a lower end, a bore with an inner diameter that tapers through a seating surface and a backside surface opposite the bore, the backside surface having an outer diameter that tapers from a position adjacent the upper end to a position adjacent the lower end; and a support area on the tool body, the support area formed of a material stronger than the dissolvable material and having a tapering bore sized and shaped similarly to the outer diameter of the backside surface, the seat mounted in the support area with the backside surface supported against the support area and the bore exposed in the inner bore.

2. The wellbore tool of claim 1 wherein the backside surface and the support area are frustoconically formed.

3. The wellbore tool of claim 1 further comprising a lock-nut arrangement for the support area to clamp the seat in the support area.

4. The wellbore tool of claim 1 wherein the seat is secured to the support area to prevent axial shifting.

5. The wellbore tool of claim 1 wherein the seat is formed entirely of dissolvable material.

6. The wellbore tool of claim 1 further comprising a projection on the seat extending radially outwardly from the backside surface, the projection engaged in a groove on the support area.

7. The wellbore tool of claim 1 further comprising a seal between the seat and the support area to seal against fluid leaking between the seat and the support area from the upper end to the lower end of the seat.

8. The wellbore tool of claim 1, wherein the seat further comprise a protective coating applied to at least a portion of an outer surface thereof.

9. The wellbore tool of claim 8, wherein the protective coating is at least partially removable from the outer surface of the seat by exposure to elements in a stimulation fluid.

10. A wellbore frac valve tool comprising: a tubular body including a wall, an upper end, a lower end and an inner bore extending from the upper end to the lower end, the inner bore having an inner diameter; a port through the wall; a sleeve valve in the inner bore and having a inner facing surface exposed in the inner bore, the sleeve valve moveable from a port-closed position over the port and a port-open position retracted from the port; a support area on the inner facing surface of the sleeve; and a ball seat in the support area and connected for movement with the sleeve, the ball seat including a portion exposed in the bore having a diameter less than the inner diameter and the portion is formed of dissolvable material.

11. The wellbore frac valve tool of claim 10 wherein the seat includes a backside surface set against the support area and the backside surface and the support area are each frustoconically formed with a taper towards the lower end of the backside surface.

12. The wellbore frac valve tool of claim 10 wherein the sleeve valve includes a lower portion and an upper portion connected by a threaded connection and the ball seat is clamped between the upper portion and the lower portion.

13. The wellbore frac valve tool of claim 10 wherein the ball seat includes a projection extending radially outwardly and the projection is clamped in a groove at the threaded connection between the upper portion and the lower portion.

14. The wellbore frac valve tool of claim 10 wherein the ball seat is formed entirely of dissolvable material.

15. The wellbore frac valve tool of claim 10 wherein the ball seat includes a seating surface exposed in the bore and the seating surface is formed entirely of dissolvable material.

16. The wellbore frac valve tool of claim 10 wherein the sleeve has a diameter no less than the inner diameter.

17. The wellbore frac valve tool of claim 10 further comprising a seal between the ball seat and the support area to seal against fluid leaking between the ball seat and the support area.

18. The wellbore frac valve tool of claim 10 further comprising a ball for sealing in the ball seat, the ball being formed of a material dissolvable in a wellbore fluid.

19. The wellbore frac valve tool of claim 10, wherein the portion of the ball seat formed of dissolvable material further comprise a protective coating applied to an outer surface thereof.

20. The wellbore tool of claim 8, wherein the protective coating is at least partially removable from the outer surface of the portion of the ball seat by exposure to elements in a stimulation fluid.

21. A method for completing a wellbore, the method comprising: landing a ball on a ball seat to actuate a frac valve tool to open ports to the formation; treating the formation;

and opening up the frac valve tool to a full bore diameter by providing time for the ball seat to dissolve.

22. The method of claim 21 wherein opening up the frac valve tool to a full bore removes the ball seat from a sleeve valve of the frac valve tool.

23. The method of claim 21 further comprising reclosing the port by moving the sleeve valve to cover the port.

24. The method of claim 21 further comprising dissolving the ball.

25. The method of claim 21, further comprising at least partially removing a protective coating from an outer surface of the seat prior to opening up the frac valve tool to a full bore diameter.