US20250297525A1

US20250297525A1 - Inflatable Downhole Apparatus with Dissolvable Actuation Mechanism

Info

Publication number: US20250297525A1
Application number: US19/083,620
Authority: US
Inventors: Michael O. Dion; Blake Arabie; Scotty Verret
Original assignee: Oilfield Service Professionals Inc
Current assignee: Oilfield Service Professionals Inc
Priority date: 2024-03-21
Filing date: 2025-03-19
Publication date: 2025-09-25
Also published as: WO2025196723A1

Abstract

An inflatable packer apparatus has a dissolvable actuation mechanism. The inflatable packer apparatus is conveyed downhole to a desired location within a wellbore. A dissolvable actuation element is dropped or pumped downhole until it lands on a seat profile, thereby obstructing or blocking a fluid pathway through the apparatus. Fluid pressure is selectively applied in order to inflate the inflatable packer apparatus at the desired downhole location. The dissolvable actuation element dissolves over a predetermined period of time, thereby reopening the fluid pathway through the apparatus.

Description

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention pertains to a sealing packer assembly that can be selectively set downhole within a wellbore, wherein said sealing element has at least one inflatable sealing element. More particularly, the present invention pertains to an inflatable packer assembly that can be selectively set at a desired location in a wellbore using an actuation mechanism that is at least partially dissolvable.

2. Brief Description of the Prior Art

Inflatable packers are well known and have been widely used in the oil and gas, mining, underground storage and other industries. In the oil and gas industry, inflatable packers frequently represent a critical component of downhole well intervention operations, in addition to wellbore construction architecture, in both cased hole and open hole environments.
Conventional inflatable packers typically comprise at least one bladder or balloon-like inflatable element operationally mounted to a central tubular body member that can be conveyed to a desired location downhole within a wellbore. After the inflatable packer assembly is positioned at a desired location within a wellbore (typically via a tubular work string), said at least one inflatable element can be selectively inflated in order to expand the inflatable element radially outward until it contacts and engages against the inner surface of a surrounding wellbore. As used herein, it is to be understood that the term “surrounding wellbore” can refer to an open-hole section of a well, or a portion of a casing string, liner or riser installed in said well.
In an inflated configuration, said inflatable element can form a barrier within the wellbore. Frictional forces between the packer assembly and the inner surface of the surrounding wellbore act to secure the packer against axial movement, while the inflatable element engages against and forms a fluid pressure seal against the inner surface of the surrounding wellbore.
Conventional inflatable packers generally comprise some combination of various components including, without limitation, a steel tubular body member, composite or plastic body mandrel, valving system, poppet check valve and port through the steel tubular mandrel body, as well as inner and outer elastomeric materials that cooperate to form an inflatable element. An axial through bore typically extends through said inflatable packer to permit fluid flow through the packer assembly.
After the inflatable packer is positioned at a desired location within a wellbore, said inflatable element is selectively inflated with at least one filler material. Filler material typically comprises a flowable fluid (such as, for example, mud, water, gas, air, or cement slurry). More specifically, said flowable fluid is pumped into the internal volume of the inflatable element, thereby causing said inflatable element to expand radially outward until it contacts the inner surface of the surrounding wellbore.
In order to inflate or fill an inflatable element, a valve apparatus is frequently used to selectively isolate the central axial through bore of the device and divert pressurized fluid into said inflatable element. Typically, an actuation element (such as, for example, a spherical ball or dart) is installed into a tubular work string or pipe, and dropped or circulated downhole until the actuation element lands on a seat or other profile within the inflatable packer assembly. In this position, the actuation element effectively blocks the central axial through bore and restricts the fluid flow capacity through said axial through bore.
As fluid is pumped, fluid pressure within the packer assembly increases until a shear-valve and/or seal sleeve valve (operated by a spring is shifted) at a predetermined pressure, thereby opening flow port(s) into the inner chamber of said inflatable element. A valve system, poppet valve, sleeve and/or elastomeric band are typically used to selectively trap the filler material within the inner chamber of the inflatable element and prevent back-flow into the central through bore of the packer.
After a sufficient volume of pressurized fluid has been pumped into said inflatable element, and the inflatable element has been fully inflated, fluid pressure must typically be increased in order to shear out or extrude the actuation element and re-open an open pathway and flow channel through the central through bore of the packer assembly. When this occurs, fluid pressure is communicated through the inflatable packer assembly, which often results in a pressure “surge” to wellbore region(s) situated below the inflatable packer assembly. In such cases, the fluid pressure surge can be highly undesirable because it can have negative impacts on open wellbore sections (whether open hole or perforated cased hole) and/or wellbore equipment situated below said inflatable packer assembly. Said negative impacts can include, without limitation, inadvertently pumping fluid into subterranean formations, damaging subterranean formations, and/or causing well-control and safety issues.
Thus, there is a need for an inflatable packer assembly that can be selectively set within a wellbore, but which eliminates undesirable pressure surges and other drawbacks associated with conventional inflatable packer assemblies.

SUMMARY OF THE INVENTION

The present invention comprises an inflatable packer assembly utilizing an actuation element that can be dissolved in-place within said inflatable packer assembly. After an inflatable packer assembly is positioned at a desired location within a wellbore, the dissolvable actuation element of the present invention (which can be shaped like a spherical ball or dart, for example) is installed into a tubular work string or pipe, and dropped or circulated downhole until the dissolvable actuation element lands on a seat or other profile within the inflatable packer assembly. In this position, the dissolvable actuation element blocks or obstructs fluid flow through the central through bore of said inflatable packer assembly.
Fluid is pumped downhole to the inflatable packer assembly. As fluid pressure is increased to a predetermined level, a shear-valve and/or pressure valve is shifted which opens flow port(s) into the internal chamber of said inflatable element. Fluid is pumped into said internal chamber to fill said inflatable element. After the expandable element has been sufficiently inflated/expanded, pumping of fluid to said inflatable packer can cease. In this configuration, the dissolvable actuation element remains disposed on said seat or other profile; as such, said dissolvable actuation element is typically immersed within or otherwise exposed to the fluid or medium used to inflate said inflatable element.
In accordance with the present invention, said actuation element is permitted to dissolve over a predetermined period of time. Once dissolved, said actuation element no longer obstructs the central through bore, which is no longer blocked or obstructed. Put another way, there is no obstruction or restriction to the central through bore of the inflatable packer assembly. As a result, there is no need to apply additional fluid pressure to said actuation element in order to clear the fluid obstruction and/or open a fluid flow path through said central through bore. Therefore, the undesirable pressure surge associated with conventional inflatable packer assemblies is eliminated. Put another way, the present invention eliminates additional unwanted fluid pressures or force exerted in a wellbore, particularly to open-hole regions and/or other wellbore equipment situated below said inflatable packer assembly.
The method and apparatus of the present invention allow for the use of an inflatable packer assembly in a wellbore without exerting undesirable fluid pressure surges or forces on open portion(s) of a wellbore or other wellbore equipment after the setting of inflatable packers. As such, the present invention reduces costs of operations in fluid loss savings, bore hole stability and wellbore productivity, and improves safety, while allowing the inflatable packer assembly to work as desired.

BRIEF DESCRIPTION OF THE DRAWINGS

The foregoing summary, as well as any detailed description of the preferred embodiments, is better understood when read in conjunction with the drawings and figures contained herein. For the purpose of illustrating the invention, the drawings and figures show certain preferred embodiments. It is understood, however, that the invention is not limited to the specific methods and devices disclosed in such drawings or figures.

FIGS. 1A and 1B depict a first sequential side view of an inflatable packer assembly deployed in a wellbore.

FIGS. 2A and 2B depict a second sequential side view of an inflatable packer assembly deployed in a wellbore.

FIGS. 3A and 3B depict a third sequential side view of an inflatable packer assembly deployed in a wellbore.

FIGS. 4A and 4B depict a fourth sequential side view of an inflatable packer assembly in a wellbore.

DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT

Before describing various embodiments of the present disclosure in further detail by way of exemplary description, examples, and results, it is to be understood that the apparatus and methods of the present disclosure are not limited in application to the details of specific embodiments and examples as set forth in the following description. The description provided herein is intended for purposes of illustration only and is not intended to be construed in a limiting sense. As such, the language used herein is intended to be given the broadest possible scope and meaning, and the embodiments and examples are meant to be exemplary, not exhaustive. Also, it is to be understood that the phraseology and terminology employed herein is for the purpose of description only and should not be regarded as limiting unless otherwise indicated as so. Moreover, in the following detailed description, numerous specific details are set forth in order to provide a more thorough understanding of the present disclosure.
It will be apparent to a person having ordinary skill in the art that the present disclosure may be practiced without these specific details. In other instances, features which are well known to persons of ordinary skill in the art have not been described in detail to avoid unnecessary complication of the description. It is intended that all alternatives, substitutions, modifications, and equivalents apparent to those having ordinary skill in the art are included within the scope of the present disclosure.
Thus, while the apparatus and methods of the present disclosure have been described in terms of particular embodiments, it will be apparent to those of skill in the art that variations may be applied to the apparatus and methods and the steps or in the sequence of steps of the methods described herein without departing from the concept, spirit, and scope of the inventive concepts. Referring to the drawings, like numerals indicate like or corresponding parts throughout the several views.
Moreover, it will be understood that various directions such as “upper”, “lower”, “bottom”, “top”, “left”, “right”, and so forth are made only with respect to explanation in conjunction with the drawings, and dimensions and material selections set forth herein and in the appended drawings are exemplary only. As a result, components may be oriented differently, for instance, during transportation and manufacturing as well as operation, may have different dimensions, and may be made of different material(s) having satisfactory characteristics. Because many varying and different embodiments may be made within the scope of the concept(s) herein taught, and because many modifications may be made in the embodiments described herein, it is to be understood that the details herein are to be interpreted as illustrative and non-limiting.
The present invention comprises an inflatable packer assembly utilizing an actuation element that can be dissolved in-place within said inflatable packer assembly. As with conventional devices, after an inflatable packer assembly is positioned at a desired location within a wellbore, the dissolvable actuation element of the present invention (which can be shaped like a spherical ball or dart, for example) is installed into a tubular work string or pipe, and dropped or circulated downhole until the dissolvable actuation element lands on a seat or other profile within the inflatable packer assembly. In this position, the dissolvable actuation element blocks or obstructs fluid flow through the central through bore of said inflatable packer assembly.
In accordance with the present invention, said actuation element is permitted to dissolve over a predetermined and preselected period of time. Once dissolved, the central through bore is no longer blocked or obstructed, and fluid can again flow through said central through bore. As a result, there is no need to apply additional fluid pressure to said actuation element in order to clear the fluid obstruction and/or open a fluid flow path through said central through bore. As a result, the present invention eliminates the practice of applying unwanted fluid pressures or force exerted in a wellbore, particularly to open-hole regions and/or other wellbore equipment situated below said inflatable packer assembly.
Referring to the drawings, an illustrative cement squeeze operation utilizing the inflatable packer assembly of the present invention in a cased borehole is depicted. It is to be understood that other downhole operations (that is, operations other than cement squeeze operations) can be performed utilizing the inflatable packer assembly of the present invention. Additionally, it is to be understood that the present invention can also be utilized in an open (that is, uncased) wellbore or bore hole.
FIGS. 1A and 1B depict a first sequential side sectional view of an inflatable packer assembly 10 of the present invention and attached bottom hole assembly disposed within a wellbore 100. As depicted in FIGS. 1A and 1B, said bottom hole assembly can generally comprise ball seat sub 30 and perforated fiberglass stinger member 40. It is to be observed that the subject bottom hole assembly configuration depicted in FIGS. 1A and 1B is exemplary only, and can comprise many other components or structures.
Wellbore 100 comprises a borehole extending into the earth's crust and penetrating subterranean formations, and defining internal wellbore surface 101. Said wellbore 100 contains fluid which can comprise drilling mud 110 and, in some cases, suspended drill cuttings 120 or other solid debris generated during the drilling process. Casing string 130 having internal surface 131 is installed within wellbore 100 in a manner well known to those having skill in the art. In the embodiment depicted in FIGS. 1A and 1B, a plurality of perforations 140 extend through casing string 130, wellbore 100 and into subterranean rock formation(s) penetrated by said wellbore 100.
Inflatable packer assembly 10 of the present invention can be conveyed into wellbore 100 on a tubular work string 200 (which can be drill pipe or other pipe) and positioned at a desired location within said wellbore 100. Inflatable packer assembly 10 includes inflatable element 20 which can be selectively expanded until it engages against and forms a seal against inner wall surface 131 of casing string 130. In the embodiment depicted in FIGS. 1A and 1B, said inflatable packer assembly 10 (and inflatable element 20, in particular) is depicted in an un-inflated configuration.
Still referring to FIGS. 1A and 1B, a dissolvable actuation element 50 of the present invention (which can be shaped like a spherical ball or dart, for example) is installed into a central through bore of tubular work string 200 and dropped and allowed to fall (or is pumped downhole using fluid pressure). A seat or other profile 60 is provided within inflatable packer assembly 10.
FIGS. 2A and 2B depict a second sequential side view of an inflatable packer assembly 10 installed within wellbore 100. In the configuration depicted in FIGS. 2A and 2B, dissolvable actuation element 50 is installed into a central through bore of tubular work string 200 and dropped or pumped downhole. Said dissolvable actuation element lands on seat profile 60 within inflatable packer assembly 10, and in that position blocks or obstructs fluid flow through the central through bore of said inflatable packer assembly 10.
Fluid is pumped (typically through the central flow bore of tubular workstring 200) until fluid pressure is increased at said packer assembly 10. Such increased fluid pressure opens flow port(s) into an internal chamber formed within inflatable element 20. After this fluid pathway into said internal chamber of inflatable element 20 is opened, fluid is pumped into said internal chamber to fill said inflatable element 20 with fluid, thereby causing said inflatable element 20 to expand radially outward until it contacts and engages against inner surface 131 of surrounding casing 130. In this configuration, dissolvable actuation element 50 remains positioned on seat 60 within the inflatable packer assembly.
A sufficient predetermined period of time is allowed to elapse so that said actuation element 50 is permitted to at least partially dissolve. After actuation element 50 at least partially dissolves, said actuation element 50 is either no longer present on said seat 60 or no longer fully blocks said seat 60; after actuation element 50 at least partially dissolves, said actuation element 50 shrinks in size. Thus, said smaller dissolved actuation element may fall through the opening of seat 60 or may dissolve entirely, thereby re-opening the fluid flow path through the central through bore of said inflatable packer assembly 10. In one embodiment, said actuation element can be selectively exposed to a specialized fluid or solvent in order to adjust (either to accelerate or decelerate) the rate of dissolution of said actuation element 50. By way of example, but not limitation, the dissolution process can be accelerated by fresh water and/or low temperatures, or retarded by high salinity fluid and/or high temperatures.
FIGS. 3A and 3B depict a third sequential side view of inflatable packer assembly 10 disposed within wellbore 100. In this configuration, inflatable element 20 of said inflatable packer assembly 100 remains expanded radially outward until it contacts and engages against inner surface 131 of the surrounding casing 130 installed in wellbore 100; when expanded, inflatable element 20 forms a fluid pressure seal against said inner surface 131 of surrounding wellbore 130.
In many instances it is desirable to deposit cement—in addition to any cement that is originally deposited in place—in or around wellbore 100. By way of example, but not limitation, when casing 130 is installed in a wellbore, it is often beneficial to selectively perforate said casing 130 in at least one desired location to form perforations 140. Cement slurry 300 can be injected (or “squeezed”) into said perforations 140, as well as surrounding rock formation(s) and void space(s) existing in the annular space formed between the external surface of said casing 130 and inner surface 101 of wellbore 100. Similarly, it is often desirable to deposit (or “spot”) a desired volume of cement slurry 300 at a desired depth within the internal bore 131 of casing string 130 to form a downhole cement plug. Although the above discussion relates to cement slurry 300, it is to be observed that other flowable treatment medium can be employed in place of said cement slurry 300 without departing from the scope of the present invention.
Still referring to FIGS. 3A and 3B, cement slurry 300 can be pumped downhole through the central through bore of tubular workstring 200 until it reaches said inflatable packer assembly 10. Because said actuation element 50 has at least partially dissolved and is no longer present on said seat 60 or other landing profile, the fluid flow path is open through the central through bore of said inflatable packer assembly 10. Thus, cement slurry 300 can be pumped through said inflatable packer assembly 10, such that a cement squeeze or cement spotting operation can be performed through the inflatable packer assembly. Importantly, because inflatable element 20 of said inflatable packer assembly 100 forms a fluid pressure seal against inner surface 131 of surrounding casing 130, cement slurry 300 or other fluid pumped below said inflatable packer assembly 10 remains below said inflatable packer assembly 10 and is not circulated back to the surface in the annular space existing between tubular workstring 200 and the inner surface 131 of casing 130.
FIGS. 4A and 4B depict a fourth sequential side view of inflatable packer assembly 10 in wellbore 100. After a cementing or other treatment operation is completed, said inflatable element 20 of said inflatable packer assembly 10 can be permitted to deflate, either by releasing or pumping trapped fluid pressure from said inflatable element 20. Said inflatable packer assembly 10 (with inflatable element 20 collapsed) and associated bottom hole assembly can be retrieved from said wellbore 100, and/or re-set at another depth within wellbore 100 utilizing the same operation described herein.
In a preferred embodiment, said actuation element 50 can comprise a magnesium alloy with rare earth elements. In downhole applications where a controlled dissolution of actuation element 50 is required, a high-salinity brine [for example, sodium chloride (NaCl) or calcium chloride (CaCl₂))] pill can be effectively spotted or deployed downhole in the vicinity of seat 60 (and actuation element 50 when landed on said seat 60) in order to expose actuation element 50 to said high-salinity brine. Magnesium alloys exhibit a high reactivity in the presence of chloride-based brines, particularly those with elevated concentrations of sodium chloride (NaCl) or calcium chloride (CaCl₂)). Alternatively, a low salinity fluid can be selectively spotted downhole in proximity to said seat 60 (and actuation element 50 disposed thereon) in order to have the opposite effect on the dissolution process of said actuation element 50.
To achieve optimal dissolution of actuation element 50, the following steps may be taken:
1. Brine Selection—Prepare a high-salinity pill using a saturated or near-saturated brine solution (e.g., 26% NaCl or CaCl₂)-based brine). For accelerated dissolution of actuation element 50, low salinity fluid such as fresh water, bromide or formate brines can be spotted in/around said actuation element 50.
2. Pumping Procedure—a fluid pill can be pumped at a controlled rate to ensure complete contact with actuation element 50. Proper circulation and residence time should be maintained in the wellbore in the vicinity of seat 60 and landed actuation element 50 to allow for effective ion exchange and dissolution of actuation element 50.
3. Chemical Enhancement (Optional)—Adding weak acids (such as acetic acid) or chelating agents can further accelerate dissolution of actuation element 50 without causing excessive reaction rates that may compromise wellbore integrity.
4. Monitoring & Validation—real-time pressure and flow monitoring may be utilized to confirm successful dissolution and clearing of any potential debris from actuation element 50 before resuming operations.
Additionally, the rate of dissolution of actuation element 50 over time can be selectively adjusted or customized to fit a particular application by taking into account certain downhole wellbore characteristics and designing said actuation element 50 accordingly. For example, the composition and design of an actuation element 50 can be selectively adjusted after taking into account wellbore characteristics for a particular downhole application such as, for example, wellbore fluid type and composition, wellbore fluid pressure, formation fluid type and composition, formation fluid pressure, downhole temperature, as well as any other wellbore factors or characteristics.
The above-described invention has a number of particular features that should preferably be employed in combination, although each is useful separately without departure from the scope of the invention. While a preferred embodiment of the present invention is shown and described herein, it will be understood that the invention may be embodied otherwise than herein specifically illustrated or described, and that certain changes in form and arrangement of parts and the specific manner of practicing the invention may be made within the underlying idea or principles of the invention.
Furthermore, the described features, structures, or characteristics may be combined in any suitable manner in one or more embodiments. In the following description, numerous specific details are provided. One skilled in the relevant art will recognize, however, that the method and/or apparatus of the present invention may be practiced without one or more of the specific details, or with other methods, components, materials, and so forth. In other instances, well-known structures, materials, or operations are not shown or described in detail to avoid obscuring aspects of the invention.

Claims

What is claimed:

1. A method for installing an inflatable packer downhole in a wellbore comprising:

a) conveying an inflatable packer assembly on a tubular pipe string to a downhole location in a wellbore;

b) dropping an actuation element in said tubular pipe string;

c) landing said actuation element on a seat profile within an internal bore of said inflatable packer assembly, wherein said actuation element at least partially obstructs said internal bore of said inflatable packer assembly;

d) inflating at least one inflatable element of said inflatable packer assembly; and

e) permitting said actuation element to dissolve to at least partially remove said actuation element from said internal bore.

2. The method of claim 1, further comprising selectively accelerating dissolution of said actuation element by decreasing salinity of fluid contacting said actuation element.

3. The method of claim 1, further comprising selectively accelerating dissolution of said actuation element by reducing temperature of fluid contacting said actuation element.

4. The method of claim 1, further comprising selectively retarding dissolution of said actuation element by increasing salinity of fluid contacting said actuation element.

5. The method of claim 1, further comprising retarding dissolution of said actuation element by increasing temperature of fluid contacting said actuation element.

6. The method of claim 1, wherein said actuation element comprises a magnesium alloy with at least one rare earth element.

7. The method of claim 6, wherein said actuation element comprises a spherical ball.

8. The method of claim 6, wherein said actuation element comprises a dart.

9. An inflatable packer apparatus comprising:

a) a body member having a central through bore;

b) an inflatable member mounted to said body member, wherein said inflatable member is configured to be selectively inflated with fluid and extend radially outward from said body member;

c) a seat disposed in said central through bore of said body member; and

d) a dissolvable actuation element configured to be received on said seat, wherein said dissolvable actuation element is configured to at least partially dissolve over a predetermined time period.

10. The apparatus of claim 9, wherein said actuation element comprises a magnesium alloy with at least one rare earth element.

11. The apparatus of claim 10, wherein said actuation element comprises a spherical ball.

12. The apparatus of claim 10, wherein said actuation element comprises a dart.

13. The apparatus of claim 9, wherein dissolution of said dissolvable actuation element accelerates when salinity of fluid contacting said actuation element is reduced.

14. The apparatus of claim 9, wherein dissolution of said dissolvable actuation element accelerates when temperature of fluid contacting said actuation element is reduced.

15. The apparatus of claim 9, wherein dissolution of said dissolvable actuation element is retarded when salinity of fluid contacting said actuation element is increased.

16. The apparatus of claim 9, wherein dissolution of said dissolvable actuation element is retarded when temperature of fluid contacting said actuation element is increased.