The present disclosure is related to downhole tools for use in a wellbore environment and more particularly to degradable plugs used to temporarily block fluid flow in a well system.
After a wellbore has been formed for the purpose of exploration or extraction of natural resources such as hydrocarbons or water, various downhole tools may be inserted into the wellbore to extract the natural resources from the wellbore and/or to maintain the wellbore. At various times during production and/or maintenance operations, it may be necessary to temporarily block the flow of fluid into or out of various portions of the wellbore or various portions of the downhole tools used in the wellbore.
A more complete and thorough understanding of the various embodiments and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings, in which like reference numbers indicate like features, and wherein:
Embodiments of the present disclosure and its advantages may be understood by referring to
Production fluids, including hydrocarbons, water, sediment, and other materials or substances found in a formation may flow from the formation into a wellbore through the sidewalls of the open hole portions of the wellbore. The production fluids may circulate in the wellbore before being extracted via a downhole assembly. The downhole assembly may include a screen to filter sediment from the production fluids flowing into the downhole assembly and a flow control device to regulate the flow of production fluids into the downhole assembly. Similarly, injection fluids may flow from a production string into the downhole assembly before flowing into the wellbore. A plug may be used to temporarily prevent flow of production or injection fluids between the downhole assembly and the wellbore. The plug may be positioned axially with respect to the flow control device. To resume fluid flow between the downhole assembly and the wellbore, the plug may be removed. To avoid the cost and time associated with manual removal of the plug, it may be removed via a chemical reaction that causes the plug to degrade within the wellbore.
Well system 100 may also include production string 103, which may be used to produce hydrocarbons such as oil and gas and other natural resources such as water from formation 112 via wellbore 114. Alternatively, or additionally, production string 103 may be used to inject hydrocarbons such as oil and gas and other natural resources such as water into formation 112 via wellbore 114. As shown in
The terms “uphole” and “downhole” may be used to describe the location of various components relative to the bottom or end of wellbore 114 shown in
Well system 100 may also include downhole assembly 120 coupled to production string 103. Downhole assembly 120 may be used to perform operations relating to the completion of wellbore 114, the production of hydrocarbons and other natural resources from formation 112 via wellbore 114, the injection of hydrocarbons and other natural resources into formation 112 via wellbore 114, and/or the maintenance of wellbore 114. Downhole assembly 120 may be located at the end of wellbore 114 or at a point uphole from the end of wellbore 114. Downhole assembly 120 may be formed from a wide variety of components configured to perform these operations. For example, components 122a, 122b and 122c of downhole assembly 120 may include, but are not limited to, screens, flow control devices, slotted tubing, packers, valves, sensors, and actuators. The number and types of components 122 included in downhole assembly 120 may depend on the type of wellbore, the operations being performed in the wellbore, and anticipated wellbore conditions.
Production fluids, including hydrocarbons, water, sediment, and other materials or substances found in formation 112 may flow from formation 112 into wellbore 114 through the sidewalls of the open hole portions of wellbore 114. The production fluids may circulate in wellbore 114 before being extracted via production string 103. Alternatively, or additionally, injection fluids, including hydrocarbons, water, and other materials, may be injected into wellbore 114 and formation 112 via production string 103 and downhole assembly 120. Downhole assembly 120 may include a screen (shown in
Downhole assembly 200 may include screen 202 and shroud 204, which may be coupled to and disposed downhole from screen 202. Both screen 202 and shroud 204 may be coupled to and disposed around the circumference of tubing 210 such that annulus 212 is formed between the inner surfaces of screen 202 and shroud 204 and the outer surface of tubing 210. Production fluids circulating in wellbore 114 may enter downhole assembly 200 by flowing through screen 202 into annulus 212. Screen 202 may be configured to filter sediment from production fluids as they flow through screen 202. Screen 202 may include, but is not limited to, a sand screen, a gravel filter, a mesh, or slotted tubing.
Downhole assembly 200 may also include flow control device 206 disposed within annulus 212 between shroud 204 and tubing 210. Flow control device 206 may include channel 214 extending there through to permit the flow of production fluids through flow control device 206. Flow control device 206 may engage with shroud 204 and tubing 210 to prevent production fluids circulating in annulus 212 from flowing between flow control device 206 and tubing 210 or shroud 204. For example, flow control device 206 may engage with the inner surface of shroud 204 to form a fluid and pressure tight seal and may engage with the outer surface of tubing 210 to form a fluid and pressure tight seal. Because flow control device 206 engages with tubing 210 and shroud 204 to form a fluid and pressure tight seal, production fluids circulating in annulus 212 flow through channel 214 rather than between flow control device 206 and tubing 210 or between flow control device 206 and shroud 204.
The flow of production fluids through channel 214 may be temporarily blocked by plug 208 disposed in a portion of annulus 212 downhole from flow control device 206. Plug 208 may be positioned in-line with and adjacent to flow control device 206, as shown in
Plug 208 may be formed of a degradable composition including a metal or alloy that is reactive under defined conditions. Plug 208 may be removed from annulus 212 using a chemical reaction that causes plug 208 to degrade, thereby avoiding manual intervention required to extract plug 208 from annulus 212 using a retrieval tool. The term “degrade” may be used to describe a process by which a component breaks down into pieces or dissolves into particles small enough that they do not impede the flow of fluids. The features of plug 208, including its degradability, are described in additional detail with respect to
Downhole assembly 200 may also include port 218, which may be removed to permit access to the portion of annulus 212 downhole from flow control device 206. Port 218 may be coupled to shroud 204 and tubing 210 via a threaded connection. Port 218 may engage with shroud 204 and tubing 210 to form a fluid and pressure tight seal. Port 218 may include a socket or slot into which a tool may be inserted. With a tool inserted into the socket or slot, port 218 may be rotated in order to disengage the threaded connection between port 218 and 204. When port 218 has been removed, plug 208 may be replaced (i.e., a new plug may be installed). For example, after plug 208 has been removed via a chemical reaction causing plug 208 to degrade, the flow of production fluids through channel 214 of flow control device 206 may again be temporarily blocked by replacing plug 208.
Plug 208 may also be used to temporarily block the flow of injection fluids from production string 103 into wellbore 114 and formation 112. For example, the flow of injection fluids from production string into wellbore 114 and formation 112 may be temporarily blocked by plug 208 positioned in-line with and axially displaced from flow control device 206, as shown in
As explained above with respect to
As explained above with respect to
A variety of mechanisms may be employed to permit plug 208 to form a fluid and pressure tight seal with shroud 204 and tubing 210 (as discussed with respect to
Although plug 208 is shown in
Although plug 208 is shown in
Plug 208 may also be formed from the metal or alloy imbedded with small particles (e.g., particulates, powders, flakes, fibers, and the like) of a non-reactive material. The non-reactive material may be selected such that it remains structurally intact even when exposed to the corrosive or acidic fluid for a duration of time sufficient to degrade the metal or alloy into pieces or particles small enough that they do not impede the flow of production fluids through channel 214 of flow control device 206 (shown in
Plug 208 may also be formed from the metal or alloy imbedded with small particles (e.g., particulates, powders, flakes, fibers, and the like) to form a galvanic cell. The composition of the particles may be selected such that the metal from which the particles are formed has a different galvanic potential than the metal or alloy in which the particles are imbedded. Contact between the particles and the metal or alloy in which they are imbedded may trigger microgalvanic corrosion that causes plug 208 to degrade. Exemplary compositions from which the particles may be formed include iron, steel, aluminum alloy, zinc, magnesium, graphite, nickel, copper, carbon, tungsten, and combinations thereof.
Plug 208 may also be formed from an anodic material imbedded with small particles of cathodic material. The anodic and cathodic materials may be selected such that plug 208 begins to degrade upon exposure to a brine fluid, which may also be referred to as an electrolytic fluid, due to an electrochemical reaction that causes the plug to corrode. A brine fluid or electrolytic fluid may include fluids containing NaCL, KCL, and other salts. Exemplary compositions from which the anodic material may be formed include one of magnesium, aluminum, and combinations thereof. Exemplary compositions from which the cathodic material may be formed include one of iron, nickel, copper, graphite, tungsten, and combinations thereof. The anodic and cathodic materials may be selected such that plug 208 is degraded sufficiently within a predetermined time of first exposure to the electrolytic fluid to form pieces or particles small enough that they do not impede the flow of production fluids through channel 214 of flow control device 206 (shown in
Plug 208 may include a coating to temporarily protect the metal or alloy from exposure to the corrosive, acidic, or electrolytic fluid. As an example, plug 208 may be coated with a material that softens or melts when a threshold temperature is reached in annulus 212 (shown in
Core 604 may be formed of a degradable composition including a metal or alloy that is reactive under defined conditions. The composition of core 604 may be selected such that core 604 begins to degrade within a predetermined time of first exposure to a corrosive or acidic fluid due to reaction of the metal or alloy from which core 604 is formed with the corrosive or acidic fluid. Additionally, the composition of plug 208 may be selected such that the degradation of plug 208 accelerates with increasing salinity or with decreasing pH of the corrosive or acidic fluid. The composition of core 604 may be selected such that core 604 degrades sufficiently to form pieces or particles small enough that they do not impede the flow of production fluids through shell 608. The corrosive or acidic fluid may already be present within annulus 212 (shown in
Core 604 may also be formed from the metal or alloy imbedded with small particles (e.g., particulates, powders, flakes, fibers, and the like) of a non-reactive material. The non-reactive material may be selected such that it remains structurally intact even when exposed to the corrosive or acidic fluid for a duration of time sufficient to degrade the metal or alloy into pieces or particles small enough that they do not impede the flow of production fluids through plug 208. When the metal or alloy degrades, the small particles of the non-reactive material may remain. The particle size of the non-reactive material may be selected such that the particles are small enough that they do not impede the flow of production fluids through plug 208. The non-reactive material may be selected from one of lithium, bismuth, calcium, magnesium, and aluminum (including aluminum alloys) if not already selected as the reactive metal or alloy, and combinations thereof.
Core 604 may also be formed from the metal or alloy imbedded with small particles (e.g., particulates, powders, flakes, fibers, and the like) to form a galvanic cell. The composition of the particles may be selected such that the metal from which the particles are formed has a different galvanic potential than the metal or alloy in which the particles are imbedded. Contact between the particles and the metal or alloy in which they are imbedded may trigger microgalvanic corrosion that causes core 604 to degrade. Exemplary compositions from which the particles may be formed include iron, steel, aluminum alloy, zinc, magnesium, graphite, nickel, copper, carbon, tungsten, and combinations thereof.
Core 604 may also be formed from an anodic material imbedded with small particles of cathodic material. The anodic and cathodic materials may be selected such that core 604 begins to degrade upon exposure to a brine fluid, which may also be referred to as an electrolytic fluid, due to an electrochemical reaction that causes the plug to corrode. Brine fluids may include fluids containing NaCl, KCl, and other salts. Exemplary compositions from which the anodic material may be formed include one of magnesium, aluminum, and combinations thereof. Exemplary compositions from which the cathodic material may be formed include one of iron, nickel, copper, graphite, tungsten, and combinations thereof. The anodic and cathodic materials may be selected such that core 604 is degraded sufficiently within a predetermined time of first exposure to the electrolytic fluid to form pieces or particles small enough that they do not impede the flow of production fluids through plug 208. The electrolytic fluid may already be present within annulus 212 (shown in
Core 604 may include a coating to temporarily protect the metal or alloy from exposure to the corrosive, acidic, or electrolytic fluid. As an example, core 604 may be coated with a material that softens or melts when a threshold temperature is reached in annulus 212 (shown in
Shell 608 may be formed of a non-reactive material. The non-reactive material may be selected such that it remains structurally intact even when exposed to the corrosive or acidic fluid for a duration of time sufficient to degrade the metal or alloy from which core 604 is formed into pieces or particles small enough that they do not impede the flow of production fluids through plug 208.
Plug 208 may further include rupture disk 618 that temporarily protects core 604 from degradation until the rupture disk is compromised allowing the corrosive or acidic fluid to contact the metal or alloy. Rupture disk 618 may be formed of a material that fractures when exposed to a threshold pressure. The threshold pressure may be a pressure greater than a pressure that occurs during operation of wellbore 114 (shown in
As discussed above with respect to
Shell 610 may include diffusion channel 612 extending radially through shell 610. When core 604 is removed from shell 610, fluid may flow through plug 208 via channel 614 and diffusion channel 612. Surface 616 of shell 610 may act as a diffuser, deflecting fluids flowing through channel 614 into diffusion channel 612. Shell 610 may be formed of a non-reactive material. The non-reactive material may be selected such that it remains structurally intact even when exposed to the corrosive or acidic fluid for a duration of time sufficient to degrade core 604 into pieces or particles small enough that they do not impede the flow of production fluids through plug 208.
Although not illustrated in
In some embodiments, the plug may be positioned in-line with and adjacent to the flow control device, as shown in
The plug may be positioned within the downhole assembly before the downhole assembly is positioned in the wellbore. Alternatively, the plug may be positioned within the downhole assembly after the downhole assembly is positioned in the wellbore. As discussed above with respect to
At step 720, the plug (or the core of the plug) may be removed in order to permit the flow of fluids into or out of the production string. As discussed above with respect to
At step 730, the flow of fluids into and out of the production string may be permitted. As discussed above with respect to step 710, production fluids circulating in the wellbore may enter the downhole assembly by flowing through a screen and into the annulus. Production fluids circulating in the annulus may flow through a flow control device disposed in the annulus and into the portion of the annulus downhole from flow the control device. From there, the production fluids may flow through an opening=formed in a sidewall of tubing coupled to the production string and into the production string. Similarly, injection fluids circulating in the production string may flow into the annulus through the opening formed in the sidewall of the tubing. From there, the injection fluids may flow through the flow control device disposed in the annulus and into the formation.
At step 740, a determination may be made regarding whether to temporarily prevent the flow of fluids into or out of the production string. If it is determined to temporarily prevent the flow of fluids into the production string, the method may return to step 710. If it is determined not to temporarily prevent the flow of fluids into the production string, the method may end.
Modifications, additions, or omissions may be made to method 700 without departing from the scope of the present disclosure. For example, the order of the steps may be performed in a different manner than that described and some steps may be performed at the same time. Additionally, each individual step may include additional steps without departing from the scope of the present disclosure.
Embodiments disclosed herein include:
A. A downhole assembly that includes a tube disposed in a wellbore, a shroud coupled to and disposed around the circumference of the tube to form an annulus between an inner surface of the shroud and an outer surface of the tube, a flow control device disposed in the annulus, and a degradable plug disposed in the annulus and positioned to prevent fluid flow between the annulus and the tube.
B. A well system that includes a production string, and a downhole assembly coupled to and disposed downhole from the production string. The downhole assembly includes a tube, a shroud coupled to and disposed around the circumference of the tube to form an annulus between an inner surface of the shroud and an outer surface of the tube, a flow control device disposed in the annulus, and a degradable plug disposed in the annulus and positioned to prevent fluid flow between the annulus and the tube.
C. A method of temporarily preventing fluid flow between a production string and a wellbore that includes positioning a degradable plug in a wellbore such that the plug prevents fluid flow between a production string and a wellbore, and triggering a chemical reaction that causes the degradable plug to degrade to a point where fluid flow between the production string and the wellbore is permitted.
Each of embodiments A, B, and C may have one or more of the following additional elements in any combination: Element 1: the downhole assembly further includes a screen coupled to and disposed uphole from the shroud and coupled to and disposed around the circumference of the tube such that an annulus is formed between an inner surface of the screen and the outer surface of the tube. Element 2: wherein the degradable plug is positioned in-line with and adjacent to the flow control device. Element 3: wherein the degradable plug is positioned in-line with and axially displaced from the flow control device. Element 4: wherein the degradable plug is engaged with the shroud and the tube to form a fluid and pressure tight seal. Element 5: wherein the degradable plug is positioned in an opening formed in a sidewall of the tube, and engaged with the tube to form a fluid and pressure tight seal and prevent fluid flow between the annulus and the tube. Element 6: wherein the degradable plug is formed of a composition that degrades within the annulus within a predetermined time of exposure to a particular fluid. Element 7: wherein the degradable plug includes a degradable plug formed of a composition that degrades within the annulus within a predetermined time of exposure to a particular fluid, and a coating formed around the degradable plug that temporarily protects the degradable plug from exposure to the particular fluid. Element 8: wherein the degradable plug comprises a first composition imbedded with particles of a second composition to form a galvanic cell. Element 9: wherein the degradable plug includes a shell including a channel extending there through, and a degradable core disposed within the channel and formed of a composition that degrades within the annulus within a predetermined time of exposure to a particular fluid. Element 10: wherein the degradable plug includes a shell including a channel extending there through, a degradable core disposed within the shell and formed of a composition that degrades within the annulus within a predetermined time of first exposure to a particular fluid, and a rupture disk that temporarily protects the degradable plug from exposure to the particular fluid, the rupture disk formed of a material that fractures when exposed to a threshold pressure. Element 11: wherein the degradable plug includes a shell including a first channel extending radially there through, and a second channel extending axially from an outer surface of the shell to the first channel, and a degradable core disposed within the second channel and formed of a composition that degrades within the annulus within a predetermined time of exposure to a particular fluid. Element 12: wherein the degradable plug includes a rupture disk that temporarily protects the degradable core from exposure to the particular fluid, the rupture disk formed of a material that fractures when exposed to a threshold pressure.
Element 13: wherein the degradable plug is positioned in fluid communication with a flow control device. Element 14: wherein the chemical reaction is triggered by exposure of the degradable plug to a particular fluid for an amount of time exceeding a threshold time. Element 15: wherein triggering the chemical reaction comprises removing a protective coating formed around the degradable plug to expose the degradable plug to a particular fluid. Element 16: wherein removing the protective coating comprises exposing the degradable plug to a threshold temperature that causes the protective coating to melt. Element 17: wherein removing the protective coating comprises exposing the degradable plug to a threshold pressure that causes the protective coating to fracture. Element 18: wherein the degradable plug degrades into particles small enough that they do not impede fluid flow. Element 19: wherein the chemical reaction causes a core of the degradable plug to degrade to a point where flow of fluids through the degradable plug is permitted. Element 20: wherein triggering the chemical reaction comprises rupturing a rupture disk to expose a core of the degradable plug to a particular fluid for an amount of time exceeding a threshold time.
Therefore, the disclosed systems and methods are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the teachings of the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present disclosure. The systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein.
Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the disclosure as defined by the following claims.
This application is a U.S. Divisional Application of U.S. patent application Ser. No. 15/111,366 filed Jul. 13, 2016, which is a U.S. National Stage Application of International Application No. PCT/US2014/073009 filed Dec. 31, 2014, which designates the United States, and which are incorporated herein by reference in their entirety.
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Number | Date | Country | |
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Number | Date | Country | |
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Parent | 15111366 | US | |
Child | 16390583 | US |