Dissolvable plug

Abstract

A pump-down plug assembly (20) for use in downhole procedures, for example the drilling and completion of multi-lateral wells, in place of a mechanical valve. The plug assembly (20) comprises a sleeve (21) with a through-bore (22) in which is located a plug element (23) which is retained by frangible fastenings (25). The assembly may be pumped down to a landing sub when it is required to seal off a section of tubing; when it is required to open the tubing, the plug element (20) may be removed by applying pressure from the surface to break the frangible fastenings (25). The housing is made from material that dissolves over a period of time.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application is a non-provisional application which claims benefit under 35 USC § 119(e) to U.S. Provisional Application Ser. No. 63 / 791967 filed Apr. 21, 2025 entitled “DISSOLVABLE PLUG.”FEDERALLY SPONSORED RESEARCH AND DEVELOPMENT

[0002] None.FIELD OF THE INVENTION

[0003] This invention relates to a dissolvable plug and to well operations employing a dissolvable plug.BACKGROUND OF THE INVENTION

[0004] When drilling or performing operations in wells in subterranean hydrocarbon reservoirs, it is often required first to close off and then to re-open tubing, such as a liner or production liner, such that the tubing can be reliably accessed hydraulically or mechanically.

[0005] Downhole mechanical valves that can perform this function are available. This function is typically performed by a valve such as a ball valve or a flapper valve pre-installed in the tubing or liner before it is run into a well. When required, such valves may be actuated (closed or re-opened) by a mechanical link (wireline or pipe) to the surface. For example, a ball valve may comprise an assembly including a ball having a through-bore. A shifting tool is deployed from the surface (via drillpipe or wireline) to rotate the ball, thereby closing or opening access to the bore.

[0006] One problem with all mechanical valves in this kind of situation is that, unless an increased outer diameter can be tolerated (which is often not the case), the inner diameter of the open valve is considerably restricted in comparison to the full inner diameter of the tubing.

[0007] Mechanically operated valves, e.g. with sliding, hinged or rotating elements, are also susceptible to failure downhole, especially due to drilling swarf, rock fragments, scale or other debris contaminating the valve mechanism and preventing its correct operation. They also incur logistical and cost challenges to source a surface deployment medium (wireline or rig).

[0008] A further issue with such valves is that access for the mechanical means of opening or closing the valve (e.g. wireline or drillpipe) is required, and in some circumstances this access is not available.

[0009] An additional disadvantage of mechanical valves is that they cannot generally be gas tight. In some situations, a gas tight barrier is required, and a mechanical valve cannot provide this. A plug, however, can be gas tight.

[0010] Many different downhole operations may require the use of such valves. One example is the drilling and completion of multi-lateral wells in a chalk field. After drilling and completing the first lateral well, the well is stimulated by pumping stimulation fluid through the drillpipe (or tubing). A so-called fluid loss valve, which would have been open during the completion of the first lateral, is then used to close off the first lateral whilst a branched well (second lateral) is drilled. In this way, loss of fluids down the first lateral and contamination of the first lateral with debris are avoided during drilling. Fluids are also prevented from coming into the well from the formation. The valve, when closed, is therefore required to withstand pressure in either direction since pressure in either direction may arise at different stages of the procedure.

[0011] Once the second lateral is drilled, the valve is opened and the second lateral then completed before both laterals are put on production. It is not possible to open the valve after the tubing is installed in the second lateral since the tubing obstructs access. For this reason, the valve is closed before completion of the second lateral and the first lateral is therefore open to contamination during this process.

[0012] US20220268128A1 (ConocoPhillips) describes the creation of a multilateral well system. A pre-installed ball valve is used to close off the first lateral (lateral A) after completion and whilst the second lateral (lateral B) is completed. An alternative mentioned in US20220268128A is a pre-installed flapper valve, which is made of a dissolvable material. In the final stage before production, the flapper valve may be dissolved with acid. Of course, both the flapper valve and ball valve are mechanical valves which need to be closed mechanically after completion of the first lateral and are susceptible to becoming jammed by downhole debris so that they cannot be closed.

[0013] US20180051533A1 (ConocoPhillips) describes a wiper dart for use in cementing operations, which includes a dissolvable ball in a central bore of the dart. In this device, the ball is designed to be dissolvable so that a passage may be opened after the cementing operation is completed. In this design, the dart, once pumped into tubing, always obstructs at least part of the tubing cross section, even after the ball is dissolved. The dart / ball is designed to withstand pressure in one direction only.

[0014] These considerations give rise to a need for an improved way of providing a two-way pressure barrier in tubing, while providing as much as possible of the full internal cross-sectional area of the tubing before installation and after opening.SUMMARY OF THE INVENTION

[0015] The invention more particularly includes a pump-down plug assembly and methods in accordance with the appended claims.

[0016] In one embodiment, a pump-down plug assembly for use in hydrocarbon wells, comprises:

[0017] a) a generally cylindrical housing of dissolvable material;

[0018] b) wherein the housing has a through-bore; and

[0019] c) a plug element located in the through-bore and retained in place by a frangible fastening;

[0020] wherein the fastening is capable of withstanding at least a first predetermined pressure on the plug element from either end of the through-bore, and wherein the fastening is capable of being broken by a second predetermined pressure, greater than the first predetermined pressure.

[0021] The housing may be made from a material designed to remain substantially intact downhole for at least 10 days, optionally at least 20, 30, 40, 50 or 60 days, optionally between 10 and 60 days, such as between 10 and 40 days. The first pressure may be between 500 and 10,000 psi differential pressure, optionally at least 1,000, 2,000, 3,000, 4,000, 5,000, 6,000, 7,000, 8,000, 9,000 or 10,000 psi differential pressure, optionally between 1000 and 7500 psi differential pressure, such as between 1,000 and 5,000 psi differential pressure. The second pressure may be above 1,000 psi differential pressure, optionally above 3,000 psi differential pressure, such as above 5,000 psi differential pressure or above 7,500 psi differential pressure; alternatively between 501 and 10,001 psi differential pressure, or optionally between 1,001 and 7,501 psi differential pressure, such as between 5,001 and 7,501 psi differential pressure. The housing may be designed to dissolve substantially completely within 60-240 days, optionally 90-120 days after removal of the plug element, such as about 60 days, about 80 days, about 100 days, about 120 days, about 140 days, about 160 days, about 180 days, about 200 days, about 220 days or about 240 days after removal of the plug element, with produced hydrocarbons flowing through the bore. The plug element may be designed to dissolve substantially completely within 120-720 days, optionally 240-360, such as about 120 days, about 200 days, about 300 days, about 400 days, about 500 days, about 600 days or about 700 days after removal of the plug element from the housing, when located in production tubing with hydrocarbons being produced through the tubing.

[0022] According to another embodiment, a method of temporarily sealing and then re-opening tubing in a hydrocarbon well comprises:

[0023] a) pumping into the tubing a plug assembly comprising a cylindrical housing with a through-bore and a plug element mounted to the housing and located within the through-bore;

[0024] b) applying pressure through the tubing to remove the plug element; and

[0025] c) passing fluid through the through-bore to dissolve the housing.

[0026] Step (b) may include applying at least a second predetermined pressure to remove the plug element from the housing by breaking a fastening between the plug element and the housing. The second pressure may be above 1,000 psi differential pressure, optionally above 3,000 psi differential pressure, such as above 5,000 psi differential pressure or above 7,500 psi differential pressure; alternatively between 501 and 10,001 psi differential pressure, or optionally between 1,001 and 7,501 psi differential pressure, such as between 5,001 and 7,501 psi differential pressure. After being pumped into the tubing, the housing may remain substantially intact downhole for at least 10 days, optionally at least 20, 30, 40, 50 or 60 days, optionally between 10 and 60 days, such as between 10 and 40 days. After removal of the plug element, the housing may dissolve substantially completely within 60-240 days, optionally 90-120 days, such as about 60 days, about 80 days, about 100 days, about 120 days, about 140 days, about 160 days, about 180 days, about 200 days, about 220 days or about 240 days after removal of the plug element.

[0027] Examples and various features and advantageous details thereof are explained more fully with reference to the exemplary, and therefore non-limiting, examples illustrated in the accompanying drawings and detailed in the following description. Descriptions of known starting materials and processes can be omitted so as not to unnecessarily obscure the disclosure in detail. It should be understood, however, that the detailed description and the specific examples, while indicating the preferred examples, are given by way of illustration only and not by way of limitation. Various substitutions, modifications, additions and / or rearrangements within the spirit and / or scope of the underlying inventive concept will become apparent to those skilled in the art from this disclosure.

[0028] The pump-down plug assembly may be configured to operate through various sequences including in which the assembly initially provides a two-way pressure barrier, thereafter transitions to an open-bore configuration through pressure-activated removal of the plug element, and subsequently restores a substantially unobstructed flow path as the remaining housing dissolves, thus enabling reliable temporary isolation without mechanical actuation while minimizing long-term restriction of the tubing bore.

[0029] The pump-down plug assembly may be configured such that a frangible fastening withstands a predetermined operational sealing pressure applied from either direction during well operations, while being selectively releasable upon application of a higher, distinct release pressure to intentionally displace the plug element.

[0030] The plug assembly may be configured to provide non-directional pressure isolation, such that the plug element and associated seal elements are symmetrically effective regardless of pressure orientation within the tubing. Prior to actuation, pressure may be applied from either direction across the plug assembly and maintained at an operational sealing pressure without displacement of the plug element, thereby enabling the assembly to function as a two-way pressure barrier during well operations. Actuation occurs only upon intentional application of a higher release pressure, at which point the plug element is displaced to open the bore.

[0031] As used herein, the terms “comprises,”“comprising,”“includes,”“including,”“has,”“having” or any other variation thereof, are intended to cover a non-exclusive inclusion. For example, a process, product, article, or apparatus that comprises a list of elements is not necessarily limited to only those elements but can include other elements not expressly listed or inherent to such process, article, or apparatus. Further, unless expressly stated to the contrary, “or” refers to an inclusive or and not to an exclusive or. For example, a condition A or B is satisfied by any one of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).

[0032] The term substantially, as used herein, is defined to be essentially conforming to the particular dimension, shape or other word that substantially modifies, such that the component need not be exact. For example, substantially cylindrical means that the object resembles a cylinder, but can have one or more deviations from a true cylinder.

[0033] Additionally, any examples or illustrations given herein are not to be regarded in any way as restrictions on, limits to, or express definitions of, any term or terms with which they are utilized. Instead, these examples or illustrations are to be regarded as being described with respect to one particular example and as illustrative only. Those of ordinary skill in the art will appreciate that any term or terms with which these examples or illustrations are utilized encompass other examples as well as implementations and adaptations thereof which can or cannot be given therewith or elsewhere in the specification and all such examples are intended to be included within the scope of that term or terms. Language designating such non-limiting examples and illustrations includes, but is not limited to: “for example,”“for instance,”“e.g.,”“In some examples,” and the like.

[0034] Although the terms first, second, etc. can be used herein to describe various elements, components, regions, layers and / or sections, these elements, components, regions, layers and / or sections should not be limited by these terms. These terms are only used to distinguish one element, component, region, layer or section from another. Thus, a first element, component, region, layer or section discussed below could be termed a second element, component, region, layer or section without departing from the teachings of the present inventive concept.

[0035] While preferred examples of the present inventive concept have been shown and described herein, it will be obvious to those skilled in the art that such examples are provided by way of example only. Numerous variations, changes, and substitutions may occur to those skilled in the art without departing from the disclosure. It should be understood that various alternatives to the examples of the disclosure described herein can be employed in practicing the disclosure. It is intended that the following claims define the scope of the disclosure and that methods and structures within the scope of these claims and their equivalents be covered thereby.BRIEF DESCRIPTION OF DRAWINGS

[0036] A more complete understanding of the present invention and benefits thereof may be acquired by referring to the follow description taken in conjunction with the accompanying drawings in which:

[0037] FIG. 1 is a schematic representation of a multi-lateral well including a valve in accordance with the prior art;

[0038] FIG. 2 is a schematic representation of a multi-lateral well including a plug assembly in accordance with the invention; and

[0039] FIG. 3 is a schematic sectional view through a plug assembly in accordance with the invention.DETAILED DESCRIPTION OF THE INVENTION

[0040] Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.

[0041] The invention will be described in the context of drilling and completing a multilateral well, but it should be understood that the invention is not limited to this type of procedure. In order to aid understanding of the invention, a technique according to the prior art is first described, with reference to FIG. 1 which shows the two branches (A and B) of a multilateral well. When creating such a well system, a bore 1 is first drilled such that it extends laterally into the hydrocarbon-bearing reservoir 2 (represented in FIG. 1 as the region beneath the broken line 3) and a liner 4 set in the bore. The liner 4 is hung from a liner hanger 5 set in large diameter casing 6 in the overburden rock 7 (the region above the broken line 3).

[0042] In the procedure, a narrower bore 8 is then drilled into rock at the end of the liner 4, and a production liner 9 run into the bore 8. The production liner 9 is hung from a liner hanger 10 set at the end of the liner 4. The production liner 9 is then completed by injecting acid through perforations 11 in the liner 9. This completed part of the well is known as “Lateral A”.

[0043] A fluid loss valve, which in this case is a ball valve 12, is pre-installed in the production tubing 9. Before lateral B is drilled, the ball valve 12 is closed to shut off the liner 9. The valve 12 is normally closed mechanically from the surface either by wireline or drillpipe. The ball valve 12 prevents produced fluid flowing out of lateral A and also prevents loss of drilling fluid into lateral A, as well preventing debris from the drilling of lateral B entering the completed lateral A. Thus, the ball valve 12 must withstand pressure in either direction in the well.

[0044] Once the ball valve 12 has been closed, a hollow whipstock 13 is then run into the bore 1 and set adjacent to the end of the production liner 9. A window 14 is then milled in liner 4 and a branched bore 15 is then drilled through the window 14 into the rock. At this point, the ball valve 12 is opened mechanically using wireline or drillpipe. A second production liner 16 is then run into the branched bore 15. The second production liner 16 is then completed via perforations 18. This second completed part of the well is known as “Lateral B”. During the running in and completion of the second liner, the first lateral is at risk of contamination since the valve is open. It is not possible to open the valve after the second liner is run in, since the liner prevents access.

[0045] Both laterals can then be put on production. Production is slightly impaired by the presence of the ball valve since it presents a constriction in the tubing bore.

[0046] Another problem with this process is that the ball valve 12 can become jammed in either an open or closed position (or halfway between). This can arise for a variety of reasons, the most common being scale or debris from drilling (e.g. swarf or rock fragments) becoming jammed in the mechanism. If the valve 12 becomes stuck in the closed position, this could mean that production from lateral A does not go ahead, with obvious large financial consequences. If the valve 12 becomes stuck in the open position before lateral B is drilled, this could prevent the drilling of lateral B, also with large financial consequences.

[0047] An embodiment of the invention is shown in FIGS. 2 and 3. Like numerals in the drawings refer to similar features. In place of the ball valve 12, a plug assembly 20 can be seen in FIG. 2. In the process described above in relation to FIG. 1, initially the plug assembly 20 is not in place. Lateral A is drilled and completed and then, when it is required to seal off lateral A, the plug assembly 20 is pumped down to a certain point in the production tubing 9, namely a landing sub. The landing sub includes small formations in its interior surface that allow the plug to be locked in place. Apart from these small formations, the landing sub has substantially the same inner bore diameter as the rest of the tubing. The formations restrict the tubing inner bore diameter by less than 5%, normally by less than 2%.

[0048] Once in place, the plug assembly 20 can withstand pressure in either direction of up to 5,000 psi. The whipstock 14 can then be run into the well and lateral B drilled. Tubing 16 may then be run into lateral B and completed whilst the plug assembly is in place, preventing debris from these operations from entering lateral A.

[0049] Once lateral B is drilled and completed, the novel features of the plug assembly 20 allow it to be opened by applying pressure from the surface in excess of 5,000 psi to remove a central plug element. Then, after a period of time, the remaining parts of the plug assembly dissolve. In this way, the bore of the production tubing 9 is returned to its original unobstructed full diameter, or substantially to its original unobstructed full diameter (subject to any minor formations projecting from the interior surface of the landing sub).

[0050] The plug assembly 20 is shown in more detail in FIG. 3. The assembly 20 comprises a generally cylindrical housing 21 with a bore 22 through it. In the bore 22 is located a cylindrical plug element 23 that blocks the bore 22. One or more ring seal elements 24 make a seal between the outer surface of the plug element 23 and the surface of the bore 22. The seal or seals 24 are capable of withstanding pressure in either direction of up to 5,000 psi without substantial leakage of well fluids. Although not necessary in this particular procedure, it is relatively simple to create seals that can also provide a gas tight seal and this may be useful in other applications of the plug assembly. The pressures that the seal is designed to withstand may vary depending on the particular well or procedure in which the plug assembly is intended to be used.

[0051] The plug element 23 is held in place by frangible connectors 25, such as shear pins. The connectors 25 are designed to withstand pressures of 5,000 psi in either direction. However, if pressure from the surface is increased beyond 5,000 psi, they are designed to break. The applied pressure would then force the plug element through the bore and down the well to be lost. In this way, the bore can be opened without the use of any valve mechanisms that may become clogged with debris and without the need for mechanical access from the surface (wireline or drillpipe). The design pressure required to break the connectors 25 may vary depending on the particular well or procedure in which the plug assembly is intended to be used.

[0052] It is possible that the frangible connection between the plug element 23 and housing 21 may be achieved by other means, such as a combination of cooperating features of the outer surface of the plug element 23 and / or inner surface of the bore 22, optionally together with frangible connecting elements. It is only necessary for the plug to move in one direction (downhole) once the connection is broken, so the plug may be completely restrained from movement in the opposite direction. There are many possibilities for achieving the desired effect and the exact design of the connection is not the subject of this patent application.

[0053] The cylindrical housing 21 is retained in place by the interaction of formations on its outer surface and / or formations on the inner surface of the production tubing 9. These interacting / cooperating formations are shown generally at 26 in a schematic way only. Their exact design is not the subject of this patent application and many different configurations are possible. One or more seal elements 27 provides a seal in either direction against pressures of up to 5,000 psi, preventing any substantial movement of well fluids past the plug assembly, including if necessary, movement of gases past the assembly.

[0054] The housing is made from a dissolvable material, e.g. a composite or an alloy, which will dissolve in a known period of time, once the plug element has been removed, in the conditions found in the well after both laterals are placed in production.

[0055] Prior to removal of the plug element 23, the housing 21 is exposed to well fluids but not to a stream of fluid passing through the bore 22. The well fluid is different in composition, at least on the distal (nearer the surface) side where it substantially comprises drilling fluid and is essentially static. In these circumstances, the rate of dissolution of the housing is relatively slow and the housing remains substantially intact for sufficient time to conduct drilling and completion of lateral B. Once the plug element has been displaced, more of the surface area of the housing is exposed to fluid and the fluid substantially all comprises produced hydrocarbons. The fluid flows through the bore at a high rate. This causes continual exposure of the plug material to fresh fluid as well as causing mechanical abrasion / wear of the surface of the bore 22. For all these reasons the rate of dissolution of the plug material is substantially increased.

[0056] In other situations, the environment is likely to be different, but it is a relatively straightforward matter to understand the conditions the plug assembly will be subject to and design the dissolvable material so that it dissolves in the required time frame.

[0057] The housing 21 is designed to remain substantially intact with the plug element in place for approximately 30 days, which is normally long enough for lateral B to be drilled and completed. Once the plug element has been dislodged, the housing is designed to dissolve substantially completely within a further 60 days. The length of time taken for the housing to dissolve away completely is not critical since hydrocarbons can be produced through the bore 22. However, the rate of production of hydrocarbons is likely to increase when more of the tubing bore cross section is free, so it is preferable to minimize the time that the housing remains in the tubing once the plug assembly has performed its function of closing off lateral A.

[0058] Once dislodged, the plug element 23 is pumped down the production tubing and is unlikely to have any material effect on production of hydrocarbons even if it remains in the tubing indefinitely. However, the plug element 23 may also be made of dissolvable material so that in the end it will substantially disappear from within the tubing. The plug element may be designed to dissolve away within 120 days in the downhole conditions it will experience during production of hydrocarbons from lateral A.

[0059] Although described herein with reference to multilateral well drilling and completion, the pump-down plug assembly is broadly applicable to a wide range of downhole operations requiring temporary isolation and subsequent re-opening of tubing. Such operations include, without limitation, zonal isolation, stimulation, pressure testing, fluid loss control, well intervention, abandonment procedures, and other situations where mechanical access from the surface is limited or undesirable. The pump-down plug assembly provides a robust two-way pressure barrier without mechanical actuation and enables restoration of a substantially full-bore flow path after opening, making it suitable for use in various well architectures, completion types, and hydrocarbon production environments.

[0060] Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.REFERENCES

[0061] All of the references cited herein are expressly incorporated by reference. The discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application.

[0062] US20220268128A1 (ConocoPhillips)

[0063] US20180051533A1 (ConocoPhillips)

Claims

1. A pump-down plug assembly for use in hydrocarbon wells, wherein the assembly comprises:a) a generally cylindrical housing of dissolvable material;b) wherein the housing has a through-bore; andc) a plug element located in the through-bore and retained in place by a frangible fastening;wherein the fastening is capable of withstanding at least a first predetermined pressure on the plug element from either end of the through-bore, and wherein the fastening is capable of being broken by a second predetermined pressure, greater than the first predetermined pressure.

2. The pump-down plug assembly according to claim 1, wherein the housing is made from a material designed to remain substantially intact downhole for at least 10 days.

3. The pump-down plug assembly according to claim 1, wherein an outer surface of the plug assembly includes a latch or profile allowing it to lock and seal into a pre-installed profile in downhole tubing.

4. The pump-down plug assembly according to claim 1, including a seal element on the outer surface of the plug assembly that seals against the tubing and withstands the first predetermined pressure.

5. The pump-down plug assembly according to claim 1, including a seal between the plug element and the through-bore of the housing that withstands the first predetermined pressure.

6. The pump-down plug assembly according to claim 1, wherein the assembly forms a gas tight seal in the tubing.

7. The pump-down plug assembly according to claim 1, wherein the dissolvable material comprises a dissolvable alloy.

8. The pump-down plug assembly according to claim 1, wherein the first pressure is between 500 and 10,000 psi differential pressure.

9. The pump-down plug assembly according to claim 1, wherein the second pressure is above 1,000 psi differential pressure.

10. The pump-down plug assembly according to claim 1, wherein the housing is designed to dissolve substantially completely within 60-240 days.

11. The pump-down plug assembly according to claim 1, wherein the plug element is designed to dissolve substantially completely within 120-720 days.

12. A method of temporarily sealing and then re-opening tubing in a hydrocarbon well, wherein the method comprises:a) pumping into the tubing a plug assembly comprising a cylindrical housing with a through-bore and a plug element mounted to the housing and located within the through-bore;b) applying pressure through the tubing to remove the plug element; andc) passing fluid through the through-bore to dissolve the housing.

13. The method according to claim 12, wherein step (b) includes applying at least a second predetermined pressure to remove the plug element from the housing by breaking a fastening between the plug element and the housing.

14. The method according to claim 13, wherein the second predetermined pressure is above 1,000 psi differential pressure.

15. The method according to claim 12, wherein, after being pumped into the tubing, the housing remains substantially intact downhole for at least 10 days.

16. The method according to claim 12, wherein, after removal of the plug element, the housing dissolves substantially completely within 60-240 days.

17. A method of drilling and completing a multi-lateral well comprising a first lateral wellbore and a second lateral wellbore, the method comprising:a) drilling and completing the first lateral wellbore;b) pumping a dissolvable plug assembly from the surface into the first lateral wellbore;c) drilling the second lateral wellbore from a position proximal of the plug assembly;d) dissolving the plug assembly or dissolving a part of it.

18. The method according to claim 17, wherein the plug assembly comprises a cylindrical housing with a through-bore and a plug element located within the through-bore, and wherein step d) involves applying pressure through the tubing to remove the plug element prior to dissolving the cylindrical housing.

19. The pump-down plug assembly according to claim 1, wherein, in use, the assembly has (i) a sealed state in which the plug element blocks the through-bore and the assembly withstands the first predetermined pressure in either direction, (ii) a released state in which the plug element is displaced from the through-bore upon application of the second predetermined pressure, and (iii) a dissolved state in which the housing dissolves after the released state to increase an available flow area through the tubing.

20. The pump-down plug assembly according to claim 19, wherein the housing remains substantially intact during the sealed state for at least 10 days and dissolves substantially completely only after the released state.

21. The pump-down plug assembly according to claim 19, wherein the released state is achieved without mechanical actuation from the surface other than application of pressure to exceed the second predetermined pressure.

22. The pump-down plug assembly according to claim 1, wherein, after removal of the plug element from the through-bore, the assembly provides a substantially unobstructed flow path such that a remaining restriction to flow through the tubing is limited to the housing until the housing dissolves.

23. The pump-down plug assembly according to claim 22, wherein dissolution of the housing after removal of the plug element restores a flow path through the tubing that is substantially equal to an internal diameter of the tubing at a landing sub in which the assembly is received.

24. The pump-down plug assembly according to claim 1, wherein, after the plug element is displaced from the through-bore, a minimum inside diameter of the through-bore available for flow is at least 80% of an inside diameter of the tubing at a location where the assembly is landed, optionally at least 90% of an inside diameter of the tubing at a location where the assembly is landed, optionally at least 95% of an inside diameter of the tubing at a location where the assembly is landed.

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