SWELLABLE CHOKE PACKER

Abstract

There is provided a swellable choke having a tubular component and at least one swelling element. Each swelling element has a swelling material carried by the tubular component, the swelling material swelling in reaction to contact with a triggering substance, such as a fluid. Each swelling element also has a ring carried by the tubular component, the ring having an outer surface that moves from a first diameter to an expanded diameter as the swelling material increases in size.

Description

RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application No. 62/157,229 filed May 5, 2015, which is hereby incorporated by reference in its entirety.

TECHNICAL FIELD

This relates to packers, such as may be used in SAGD or other downhole operations to control flow.

BACKGROUND

In SAGD (steam assisted gravity drainage) operations, steam is injected into a well in order to heat and mobilize heavy oil in an oil-bearing formation. Steam is injected through an injection tubing string, and returns through an annulus that is formed between the casing and the injection string. An isolation packer is generally installed between the injection tubing string and the casing in order to control the circulation of the steam. Packers may also be used in other downhole operations and in other types of wells, such as cyclic wells, which generally have one leg that is used for both stimulation and production. Alternatively, steam flow control devices and production inflow control devices may be used to control fluid flow.

Commonly used packers include cup-type packers, full swellable packers, and packing metal ring packers. In addition, PCT Patent Publication No. WO 2012/0136258 (Aakre et al.) entitled “Temperature Responsive Packer and Associated Hydrocarbon Production System” discloses a packer with a fluid-filled bellows that expands when heated to restrict the annulus.

SUMMARY

According to an aspect, there is provided a swellable choke packer including a tubular component and at least one swelling element, each swelling element including a swelling material carried by and, optionally, in thermal contact with the tubular component, the swelling material increasing in size when contacting a triggering substance, and optionally as the tubular component is heated; and a ring carried by the tubular component, the ring having an outer surface that moves from a first diameter to an expanded diameter as the swelling material swells.

According to another aspect, the triggering substance may include water or a hydrocarbon.

According to another aspect, the ring may be a split ring and the ring may shield the swelling element from wear.

According to another aspect, the ring may be made from spring steel, stainless steel, a different metal or a composite.

According to another aspect, the swelling material may be a heat-responsive rubber that further expands in response to being heated.

According to another aspect, the swellable choke may further comprise two or more swelling elements axially spaced along the tubular component.

According to another aspect, each swelling element may comprise a spacer element positioned axially adjacent to each side of the swelling material.

According to another aspect, the spacer elements may restrict expansion of the swelling material to a radial direction and provide a seal surface within the choke.

According to another aspect, the tubular component may be a mandrel.

According to another aspect, there is provided a method of treating a hydrocarbon-producing well, including the steps of: providing a swellable choke according to the invention; attaching the swellable choke in line with a tubing string; inserting the tubing string into the hydrocarbon-producing well; and changing at least one downhole condition to cause the swellable choke to swell and engage an inner surface of the hydrocarbon-producing well.

According to another aspect, the downhole condition may be changed by causing at least one of water or hydrocarbons to come into contact with the swellable choke.

According to another aspect, the downhole condition may be changed by changing the temperature to which the swellable choke is exposed.

According to another aspect, the ring may be allowed to slide along an inner surface of the hydrocarbon-producing well as the swellable choke moves along the hydrocarbon-producing well.

In other aspects, the features described above may be combined together in any reasonable combination as will be recognized by those skilled in the art.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features will become more apparent from the following description in which reference is made to the appended drawings, the drawings are for the purpose of illustration only and are not intended to be in any way limiting, wherein:

FIG. 1 is a side elevation view of an expanding isolation packer.

FIG. 2 is a front elevation view of the expanding isolation packer shown in FIG. 1.

FIG. 3 is a perspective view of the expanding isolation packer shown in FIG. 1.

FIG. 4 is a cross-section of the side elevation view of the expanding isolation packer shown in FIG. 1.

FIG. 5 is a cut-away side elevation view of a SAGD injector with expanding isolation packers.

FIG. 6 is a side elevation view of the SAGD injector shown in FIG. 5.

FIG. 7 is a side elevation view of the portion of the SAGD injector of FIG. 5 shown in circle A, showing an expanding isolation packer.

FIG. 8 is a side elevation view of the portion of the SAGD injector of FIG. 5 shown in circle B, showing a flow control device.

DETAILED DESCRIPTION

A detailed description of one or more embodiments of the invention is provided below along with accompanying figures that illustrate the principles of the invention. The invention is described in connection with such embodiments, but the invention is not limited to any embodiment. The scope of the invention is limited only by the claims and the invention encompasses numerous alternatives, modifications and equivalents. Numerous specific details are set forth in the following description in order to provide a thorough understanding of the invention. These details are provided for the purpose of example and the invention may be practiced according to the claims without some or all of these specific details. For the purpose of clarity, technical material that is known in the technical fields related to the invention has not been described in detail so that the invention is not unnecessarily obscured.

The term “invention” and the like mean “the one or more inventions disclosed in this application”, unless expressly specified otherwise.

The terms “an aspect”, “an embodiment”, “embodiment”, “embodiments”, “the embodiment”, “the embodiments”, “one or more embodiments”, “some embodiments”, “certain embodiments”, “one embodiment”, “another embodiment” and the like mean “one or more (but not all) embodiments of the disclosed invention(s)”, unless expressly specified otherwise.

The term “variation” of an invention means an embodiment of the invention, unless expressly specified otherwise.

A reference to “another embodiment” or “another aspect” in describing an embodiment does not imply that the referenced embodiment is mutually exclusive with another embodiment (e.g., an embodiment described before the referenced embodiment), unless expressly specified otherwise.

The terms “including”, “comprising” and variations thereof mean “including but not limited to”, unless expressly specified otherwise.

The terms “a”, “an” and “the” mean “one or more”, unless expressly specified otherwise. The term “plurality” means “two or more”, unless expressly specified otherwise. The term “herein” means “in the present application, including anything which may be incorporated by reference”, unless expressly specified otherwise.

The term “e.g.” and like terms mean “for example”, and thus does not limit the term or phrase it explains.

The term “respective” and like terms mean “taken individually”. Thus if two or more things have “respective” characteristics, then each such thing has its own characteristic, and these characteristics can be different from each other but need not be. For example, the phrase “each of two machines has a respective function” means that the first such machine has a function and the second such machine has a function as well. The function of the first machine may or may not be the same as the function of the second machine.

Where two or more terms or phrases are synonymous (e.g., because of an explicit statement that the terms or phrases are synonymous), instances of one such term/phrase does not mean instances of another such term/phrase must have a different meaning. For example, where a statement renders the meaning of “including” to be synonymous with “including but not limited to”, the mere usage of the phrase “including but not limited to” does not mean that the term “including” means something other than “including but not limited to”.

Neither the Title (set forth at the beginning of the first page of the present application) nor the Abstract (set forth at the end of the present application) is to be taken as limiting in any way the scope of the disclosed invention(s). An Abstract has been included in this application merely because an Abstract of not more than 150 words is required under 37 C.F.R. Section 1.72(b) or similar law in other jurisdictions. The title of the present application and headings of sections provided in the present application are for convenience only, and are not to be taken as limiting the disclosure in any way.

Numerous embodiments are described in the present application, and are presented for illustrative purposes only. The described embodiments are not, and are not intended to be, limiting in any sense. The presently disclosed invention(s) are widely applicable to numerous embodiments, as is readily apparent from the disclosure. One of ordinary skill in the art will recognize that the disclosed invention(s) may be practiced with various modifications and alterations, such as structural and logical modifications. Although particular features of the disclosed invention(s) may be described with reference to one or more particular embodiments and/or drawings, it should be understood that such features are not limited to usage in the one or more particular embodiments or drawings with reference to which they are described, unless expressly specified otherwise.

A swellable choke packer, generally identified by reference numeral 10, will now be described with reference to FIG. 1 through 8. As used herein, the term choke refers to an element that restricts fluid flow in a wellbore, but does not necessarily provide against flow, and may not hold constant pressure against the fluid flow.

Referring to FIG. 1, swellable choke 10 has a tubular component 12, such as a mandrel. Choke 10 as shown has two swelling elements 14, but may also have only one or may have more than two. Referring to FIG. 4, each swelling element 14 includes a swelling material 16 that swells in the presence of a particular substance, such as water, hydrocarbons, a compound that is reactive to swelling material 16, or a combination of any or all of the foregoing. Swelling material 16 is carried by the tubular component, and is in thermal contact with the tubular component. Swelling material 16 is selected from different swellable materials, such as a swellable rubber, as are known in the art. The swellable material can be any material with a sufficiently high coefficient of expansion. While swelling material 16 may be a temperature-responsive material as well, it will be understood that swelling material relies primarily on water, hydrocarbons, or both as an actuator to swell. In an embodiment of the invention swellable material 16 absorbs fluids causing the swelling to occur. Furthermore, as swelling material 16 is generally intended to be used in high temperature and pressure applications, it will preferably be selected to withstand these conditions sufficiently to accomplish its intended use.

Each swelling element 14 has an outer ring 18 carried by tubular component 12, where outer ring 18 has an outer surface 20 that moves from a retracted outer diameter to an expanded outer diameter as swelling material 16 increases in size. Outer ring 18 is formed such that it is provided with the ability to expand from a first diameter to an expanded diameter, as will be understood by those skilled in the art. For example, the outer ring may be a split ring as shown in FIG. 3, allowing outer ring 18 to expand. Outer ring 18 is preferably formed from a metal, such as spring steel, or stainless steel, a different metal or a composite that allows for a sliding engagement between outer ring 18 and the casing string of the well as the ring 18 expands, while also resisting such elements as wear, high temperature and pressure, chemicals, etc., thereby protecting swelling material 16 from wear during movement and choke flow. The material for outer ring 18 may be selected by those of ordinary skill to have the necessary properties based on the anticipated degree of expansion and force applied and may be any material suitable for the purpose. Preferably, outer ring 18 is made from a material that has a low enough coefficient of friction relative to the inner surface of the casing that it is able to slide within the casing or liner as the inner or outer tubing strings move relative to each other, such as may occur when repositioning a tubing string, or due to the thermal expansion of metal.

Referring to FIG. 3, choke 10 is shown with two swelling elements 14 axially spaced along the length of the tubular component 12, where the swelling elements 14 are separated by a spacer element 22 placed axially adjacent to each side of swelling material 16 of swelling element 14, as shown in FIG. 4. Spacer elements 22 restrict expansion of the swelling material to a radial direction, causing the outer ring 18 to expand outwards against the inner surface of the outer tubular element, such as a production or injection casing string or liner 23 as shown in FIGS. 7 and 8, as the case may be. Spacer elements 22 also act as a seal at the edge of swelling elements 14.

Referring to FIG. 4, the assembly of one embodiment of choke 10 will be described. First spacer element 24 has a threaded connection and is threaded onto tubular component 12. First swelling element 26 is next slid onto tubular component 12, followed by second spacer element 28 and second swelling element 30. Finally, third spacer element 32 is slid onto tubular component 12. Third spacer element 32 has openings 34 as shown in FIG. 3. Lock wire 36 is fed through openings 34 to allow third spacer element 32 to be locked into place as shown in FIG. 4.

Referring to FIG. 5 and FIG. 6, one possible arrangement in which choke 10 may be used is shown. FIG. 5 shows SAGD injector 38. Injector 38 has five chokes 10, although it will be understood by those skilled in the art that any number of chokes 10 may be used, subject to the requirements of the tasks they are used for. Referring to FIG. 7, choke 10 is placed within the SAGD injector 38. Referring to FIG. 8, injector 38 has flow control devices 40 to control the flow of steam into the wellbore through slots 33 in casing string 23. Slots 23, which may also be openings of other shapes, such as circular holes or a screen also act as a screen for sand control and allow the passage of water and hydrocarbons. During use of the depicted example, steam is passed through the interior of injector 38 into the well via flow control devices 40 and slotted liner 23. The metal of tubular component 12 conducts heat to swellable material 16, which may further cause swelling material 16 to expand. Spacer elements 22 limit the expansion of swelling material 16 in the radial direction, causing it to expand radially and moving outer ring 18 outward to engage the inner surface of casing string 23. The seal may not be air-tight, and may be a leaky seal as required and is used to prevent or reduce the amount of injected steam or other fluids, such as hydrocarbons, that travels along the annular space inside of casing string 23. Outer ring 18 is preferably a metal, split ring with overlapping ends as shown, which allows it to expand radially and still sufficiently engage the inner surface of casing string 23. Ideally, swelling material 16 is selected such that the outward pressure is sufficient to press outer ring 18 outward, but not sufficient to create a binding or high friction engagement between outer ring 18 and the inner surface of casing string 23. This engagement permits choke 10 to slide axially and shield swellable material 16 in the case of changing temperatures of the well causing expansion and contraction of the work string. Outer ring 18, after swelling of swelling material 16 also serves to centralize tubular component 12. The use of chokes 10 remove the need for expansion joints and potential leaks resulting from such joints and provide access to tools down hole.

As will be understood, the design and use of choke 10 will depend on the requirements of the reservoir, the configuration of the injection nozzles or ports and their placement, etc. Furthermore, the use of choke 10 can provide zonal isolation without the use of expansion joints. In an alternative embodiment of the invention choke 10 may have a centralizer (not shown) to prevent outer ring 18 from being crushed.

One example of choke 10 will now be described. Choke 10 may be used as a SAGD or cyclic flow choke device. There are several applications for the choke 10 for flow restriction. It may be placed for multi stage zonal restriction as shown in FIGS. 5 and 6, or as an above the liner packer as a positive pressure choke for back side inert gas injection (not shown). Choke 10 may use high temperature swellable rubber to engage the outer ring or rings 18. This allows outer rings 18 not to be fully engaged downhole, but to drift until it is necessary to expand to engage the outer casing string 23. Presently, existing products require the hole to be cleaned and clear of debris so it won't get stuck or act like a scraper. When the wells are shallow and deviated, it is a challenge pushing all the tools downhole in a multi zone completion. Choke 10 will still require some hole cleaning but drag will be less of an issue with the presently described choke 10. Each outer ring 18 may act as a choke off point without providing a positive pressure seal. As such, choke 10 only provides a flow reduction at the metal to metal contact which would allow the choke 10 to slide up or down hole due to the expansion of the liner and injection string during temperature change, which could otherwise lead to buckling on the casing string 23. The choke 10 can still act as a flow diverting and pressure choke tool. Without buckling, it then extents the life of the well service life and reduces the amount of tools in the hole that may cause a leak problem. The swellable rubber material can be configured to expand at various rates to control the energy on the expansion ring or rings engagement load. Reducing the load reduces drag but also reduces the choke flow. An optimized balance of acceptable drag, zonal pressure, choke control and buckling may be determined before installation. The packer can be custom designed with various options of metal rings and swellable outer rings. The metal rings can sandwich between swellable rings to increase the pressure hold while still maintaining movement.

Further, in the methods taught herein, the various acts may be performed in a different order than that illustrated and described. Additionally, the methods can omit some acts, and/or employ additional acts.

These and other changes can be made to the present systems, methods and articles in light of the above description. In general, in the following claims, the terms used should not be construed to limit the invention to the specific embodiments disclosed in the specification and the claims, but should be construed to include all possible embodiments along with the full scope of equivalents to which such claims are entitled. Accordingly, the invention is not limited by the disclosure, but instead its scope is to be determined entirely by the following claims.

Claims

1. A swellable choke comprising:

a tubular component;

at least one swelling element, each swelling element comprising: a swelling material carried by the tubular component, the swelling material increasing in size as the tubular component encounters a triggering substance; and a ring carried by the tubular component, the outer ring having an outer surface that moves from a first diameter to an expanded diameter as the swelling material swells.

2. The swellable choke of claim 1 wherein the triggering substance comprises water.

3. The swellable choke of claim 1 wherein the triggering substance comprises a hydrocarbon.

4. The swellable choke of claim 1, wherein the ring is a split ring.

5. The swellable choke of claim 4, wherein the ring is made from spring steel or a composite, resilient material.

6. The swellable choke of claim 1 wherein the ring is configured to protect the swelling element from wear.

7. The swellable choke of claim 1 wherein the swelling material is in thermal contact with the tubular component.

8. The swellable choke of claim 7, wherein the swelling material further swells as a result of a change in temperature.

9. The swellable choke of claim 1, further comprising two or more swelling elements axially spaced along the tubular component.

10. The swellable choke of claim 1, further comprising a spacer element positioned axially adjacent to each side of the swelling material.

11. The swellable choke of claim 1, wherein the spacer elements restricts expansion of the swelling material to a radial direction.

12. The swellable choke of claim 1, wherein the tubular component is a mandrel.

13. A method of treating a hydrocarbon-producing well, the method comprising the steps of:

providing a swellable choke as claimed in claim 1;

attaching the swellable choke in line with a tubing string;

inserting the tubing string into the hydrocarbon-producing well;

changing at least one downhole condition to cause the swellable choke to swell and engage an inner surface of the hydrocarbon-producing well.

14. The method of claim 13, wherein the downhole condition is changed by causing at least one of water and hydrocarbons to come into contact with the swellable choke.

15. The method of claim 13, wherein the downhole condition is changed by changing the temperature to which the swellable choke is exposed.

16. The method of claim 13, further comprising the step of allowing the ring to slide along an inner surface of the hydrocarbon-producing well as the swellable choke moves along the hydrocarbon-producing well.

17. The method of claim 14, wherein the downhole condition is changed by changing the temperature to which the swellable choke is exposed.