PLUG-ACTUATED SUB

Abstract

A plug-actuated sub can include a housing disposed in the wellbore tubular and a plug seat located inside the housing. The plug-actuated sub also has a flapper and a flapper seat located inside the housing. The flapper seat is axially slidable between a first position and a second position in the housing. The plug seat is configured to release the flapper onto the flapper seat when the plug seat is shifted. It is emphasized that this abstract is provided to comply with the rules requiring an abstract, which will allow a searcher or other reader to quickly ascertain the general subject matter of the technical disclosure.

Description

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure

This disclosure relates generally to oilfield downhole tools and more particularly to methods and devices for actuating a downhole tool using a plug-actuated sub.

2. Description of the Related Art

Wellbore operations such as drilling, wireline logging, completions, perforations and interventions are performed to produce oil and gas from underground reservoirs. Wellbores can extend thousands of feet underground to the underground reservoirs. Some of these operations require downhole tool actuation such as stroking or rotating a tool, or opening ports. Hydrostatic, mechanical, hydraulic, electrical or electromagnetic means are used to actuate a tool. In some aspects, the present disclosure is directed to methods and devices for actuating a downhole tool using a plug-actuated sub.

SUMMARY OF THE DISCLOSURE

In one aspect, the present disclosure provides a plug-actuated sub for performing a downhole operation in a wellbore tubular. The plug-actuated sub may include a housing disposed in the wellbore tubular, and a plug seat located inside the housing. The plug-actuated sub may also have a flapper and a flapper seat located inside the housing. The flapper and the flapper seat may be axially slidable between a first position and a second position in the housing. The plug seat is configured to release the flapper onto the flapper seat when the plug seat is shifted.

In another aspect, the present disclosure provides a method for performing a downhole operation in a wellbore tubular. The method may include disposing a control device in the wellbore tubular. The control device may include a housing disposed in the wellbore tubular, and a plug seat, a flapper and a flapper seat located inside the housing. The method may also include dropping a plug into the wellbore tubular, allowing the plug to seat on the plug seat, shifting the plug seat, releasing the flapper, rotating the flapper, seating the flapper on the flapper seat, and sliding the flapper inside the housing axially.

Illustrative examples of some features of the disclosure thus have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features of the disclosure that will be described hereinafter and which will form the subject of the claims appended hereto.

BRIEF DESCRIPTION OF THE DRAWINGS

For detailed understanding of the present disclosure, references should be made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein:

FIG. 1 shows an exemplary plug-actuated sub with a flapper in an open position according to the present disclosure;

FIG. 2 shows an exemplary plug-actuated sub with a flapper in a partially closed position according to the present disclosure;

FIG. 3 shows an exemplary plug-actuated sub with a flapper in a closed position according to the present disclosure;

FIG. 4 shows an exemplary plug-actuated sub and a sleeve before actuated by a plug according to the present disclosure; and

FIG. 5 shows an exemplary plug-actuated sub and a sleeve after being actuated by a plug according to the present disclosure.

DETAILED DESCRIPTION OF THE DISCLOSURE

The present disclosure relates to devices and methods for actuating downhole tools using a plug-actuated sub. The plug-actuated sub is installed into a production string of a well. The plug-actuated sub actuates a downhole tool by using a plug to axially displace a seat to unlock a flapper. The unlocked flapper rotates to a closed position, which seals the bore of the sub. The seal allows an operator to increase the hydrostatic force above the flapper and thereby hydraulically actuate the downhole tool. Illustrative plug-actuated subs are described below.

FIG. 1 shows one non-limiting embodiment of the plug-actuated sub 9 for hydraulically actuating a downhole tool. The plug-actuated sub 9 includes a housing 20 that encloses the flapper assembly 30 and a plug seat 40. The flapper assembly 30 is positioned uphole of the plug seat 40. Thus, fluid flows from the surface, through the flapper assembly 30, and then through the plug seat 40. During activation, the flapper assembly 30 and the plug seat 40 can slide axially in the downhole direction a predetermined distance inside the plug-actuated sub 9. This sliding movement can be used to actuate the flapper assembly 30 and perform other functions such as open fluid ports.

In one arrangement, the flapper assembly 30 has a flapper 32 that has an open position wherein fluid can flow across the plug-actuated sub 9 and a closed position wherein fluid flow is completely blocked and cannot flow across the plug-actuated sub 9. The flapper assembly 30 can have a rotational member 34, such as a pin or a torsional spring, around which the flapper 32 rotates to the closed position. The flapper assembly 30 has a flapper seat 38 that has a seating surface 37 to form a fluid-tight seal between the housing 20 and the flapper 32.

The plug seat 40 is located in the housing 20 and connected to the flapper seat 38. The plug seat 40 has a flow bore 48 through which fluid flows or other downhole devices can pass. The plug seat 40 also includes a surface 44 that can receive a plug 50. When the plug 50 lands on the surface 44, the plug 50 blocks the fluid flow through the flow bore 48. In the pre-activated condition, a fastening member 42, such as shear screws, secures the plug seat 40 to the housing 20. During activation, the flapper assembly 30 and the plug seat 40 move axially, as shown in FIGS. 2 and 3. The housing 20 has a constraint 29 positioned downhole of the plug seat 40 to limit the axial movement of the plug seat 40 in the downhole direction. In one non-limiting embodiment, the constraint 29 may be a groove, slot, or profile that receives a fitting member 46, such as a snap ring.

The housing 20 has a latch 25 to lock the flapper 32 in the open position. The latch 25 can be a protrusion machined, welded or otherwise assembled to the housing 20. The housing 20 can be positioned along a production string or other wellbore tubular. The housing 20 is a hollow cylinder that can receive the flapper assembly 30 and the plug seat 40. The housing 20 may provide sealing for these components from the wellbore fluids present in the subterranean formation. The housing 20 may be located in the bottom hole assembly and be threaded to the production string.

In one method of operation, the plug-actuated sub 9 is deployed in a wellbore tubular (not shown). The flapper 32 and the flow bore 48 are initially open to allow fluid flow through the sub 9 as shown in FIG. 1. The plug 50 is dropped from the surface. The plug 50 lands on the curved surface 44 of the plug seat 40 and closes the flow bore 48 as shown in FIG. 2. The fluid flow from the surface applies a push force on the plug seat 40. The fastening member 42 releases the plug seat 40, for example shear screws may be sheared. The fluid shifts the plug seat 40 slightly in the downhole direction. The plug 50 and the plug seat 40 holds enough pressure to unlatch the flapper assembly 30, which is relatively low compared to the necessary force to shift the flapper assembly 30. The flapper assembly 30 moves axially with the plug seat 40. Therefore, the flapper 32 is freed from the latch 25.

FIG. 3 shows the flapper 32 seated on the flapper seat 38, and the plug seat 40 and the flapper assembly 30 completely shifted in the downhole direction. The pressure of the fluid pumped from the surface pushes the flapper 32 to the closed position and applies a thrusting force on the flapper 32 to slide the flapper assembly 30 and the plug seat 40 toward the constraint 29. The fitting member 46 snaps into the groove of the constraint 29 and axially fixes the plug seat 40 with respect to the housing 20. At this point, the flapper 32 substantially hydraulically isolates a bore section uphole of the flapper 32 and the bore downhole of the flapper 32. Thus, the hydraulic pressure uphole of the flapper assembly 30 may be increased to actuate the downhole tool. By “substantially,” it is meant that the isolation is sufficient to increase the fluid pressure to a value required to actuate the downhole tool, i.e., some leakage may be present.

The plug-actuated sub 9 may be run in conjunction with other bottom hole assemblies inside a wellbore tubular such as a casing, liner, tubing or other suitable tubular. A conveyance device (not shown) is used to deploy the plug-actuated sub 9 into the wellbore tubular. The sub 9 may be connected to the conveyance device through any suitable means. The conveyance device may be tubing, coiled tubing, drillpipe, wireline, slickline, electric line or a combination thereof.

The plug-actuated sub 9 requires a lower stress on the plug seat 40 that is exposed to high fluid pressure when a plug 50 seats on the surface 44. The plug-actuated sub 9 that can work with high fluid pressure can receive a larger plug 50, and consequently, have a larger flow bore 48. If multiple zones and multiple plug actuated subs 9 are involved, then the plug-actuated sub 9 may be used to meet the need of smaller incremental sizes of plug seats 40 and larger flow bores 48.

It should be appreciated that the plug-actuated sub 9 of the present disclosure is subject to various embodiments. In a non-limiting embodiment of the present disclosure, the flapper 30 may have a straight or a slim-curved shape. Also, the flapper 32 may be located in a recess 28 of the housing 20 in the open position. In that case, the inner surface of the latch 25 may be flush with the inner wall of the housing 20.

In some embodiments, one or more devices may be used to assist in closing the flapper 32. For instance, the housing 20 may have an inclined surface 21 as shown in FIGS. 1-3 facing the flapper assembly 30. The inclined surface 21 of the housing 20 pushes the flapper 32 to the closed position. Or, a spring such as a bow spring may be used at the back of the flapper 32 between the housing 20 and the flapper 32. The bow spring can provide the initial push force to close the flapper 32. The fluid flow, then, further pushes the flapper 32 to the closed position.

Also, the housing 20 may include an additional member 22 to conveniently assemble or insert the flapper assembly 30 and the plug seat 40 into the housing 20. The additional member 22 is similar to the housing and may be connected to the housing 20 with a thread or other connection means. First, the flapper assembly 30 may be inserted in the housing 20, and the flapper 32 may be moved to the open position. Last, the additional member 22 may be placed and the flapper 32 may suitably be fastened to the latch 25 that may be located in the additional member 22. In addition, the housing 20 may need features such as grooves may be machined on the inner surface. Closer these features to the opening of the housing 20, the easier is the machining.

In another embodiment and method, the plug seat 40 shifts and exposes the ports 24 of the housing 20 to the flow bore 48. A well treatment operation such as fracing may follow to pump frac fluids through the ports 24. After fracing is completed, the subterranean fluids may flow up the well. The plug-actuated sub 9 according to the present disclosure can be used for various well treatment operations. The well treatment operations include well cleaning, hydraulic fracturing, acidizing, cementing, plugging, pin point tracer injection or other well stimulation or intervention operations. Stimulation operation is an operation that changes the characteristic of the formation or the fluid inside the formation.

Another non-limiting embodiment of the present disclosure is shown in FIGS. 4 and 5. The plug-actuated sub 9 may include a downhole member 60 affixed to the flapper assembly 30. The downhole member 60 may be a sleeve, slips of a completion or production tool, or any member that uses axial movement during actuation. The downhole member 60 is affixed to the flapper seat 38 by a connector 62 such as a rod or a sleeve. In many respects, the plug-actuated sub 9 of FIGS. 4 and 5 is similar to that shown in FIGS. 1-3.

As shown in FIG. 4, a restriction member 45, such as a protrusion, sleeve or collet, attached to the plug seat 40 holds the flapper seat 38 at an axially fixed location in the housing 20. Then, the plug 50 is dropped in the well, and fluid is pumped to seat the plug 50 on the plug seat 40. The fluid pushes the plug seat 40 in the downhole direction. FIG. 5 shows the flapper seat 38a and the flapper 32a as freed from the restriction member 45 of the plug seat 40. When freed, the flapper seat 38a may have independent axial movement with respect to the plug seat 40. Or, the flapper assembly 30 may move with the plug seat 40. In either case, because the flapper seat 38a is connected to the downhole member 60 by the connector 62, the downhole movement of the flapper assembly 30 pulls the downhole member 60 and thereby mechanically actuates the downhole tool.

A stop member 36 located on the outer surface of the flapper seat 38 may lock the flapper seat 38 in the axial direction when the flapper seat 38 reaches a stop 26 of the housing 20. The stop member 36 may be a snap ring, and the stop 26 may be a groove. The stop member 36 and the stop 26 combination may be replaced with a shoulder or other latch mechanisms. Also, the constraint 29 that limits the movement of the plug seat 40 in the downhole direction may also be a shoulder. Or, the constraint 29 may not exist at all.

In one embodiment and method, the downhole member 60 may have openings 64. The ports 24 and the openings 64 are aligned to treat the formation when the stop 26 limits the axial downhole movement of the flapper assembly 30. Or, the sub 9 may be used to create a stroke action to set a downhole tool.

In another embodiment and method, multiple plug-actuated subs 9 may be set at different depths along a wellbore. Each plug-actuated sub 9 may have incremental sizes of flow bore 48 as the plug-actuated sub 9 gets deeper in the well. For instance, one plug seat 40 may have a larger inner diameter than the next plug seat 40 deeper in the well. Therefore, plugs 50 may seat at correspondingly sized plug seats 40.

In another embodiment and method of operation, after a certain passage of time or based on a certain stimulus, some or all components of the plug-actuated sub 9 can be formed of a degradable material. For instance, the flapper 32 may be partially or totally degradable. For example, the operator may pump fluid downhole to accelerate the degradation of the flapper 32.

Herein, “degradable” means disintegrable, corrodible, decomposable, soluble, or at least partially formed of a material that can undergo an irreversible change in its structure. Examples of suitable materials and their methods of manufacture are given in United States Patent Publications No. 2013/0025849 (Richard and Doane) and 2014/0208842 (Miller et al.), and U.S. Pat. No. 8,783,365 (McCoy and Solfronk), which patent Publications and patents are hereby incorporated by reference in their entirety. A structural degradation may be a change in phase, dimension or shape, density, material composition, volume, mass, etc. The degradation may also be a change in a material property; e.g., rigidity, porosity, permeability, etc. Also, the degradation occurs over an engineered time interval; i.e., a predetermined time interval that is not incidental. Illustrative time intervals include minutes (e.g., 5 to 55 minutes), hours (1 to 23 hours), or days (2 to 3 or more days).

The degradable material can be high-strength and lightweight, and have fully-dense, sintered powder compacts formed from coated powder materials that include various lightweight particle cores and core materials having various single layer and multilayer nanoscale coatings. These powder compacts are made from coated metallic powders that include various electrochemically-active (e.g., having relatively higher standard oxidation potentials) lightweight, high-strength particle cores and core materials, such as electrochemically active metals, that are dispersed within a cellular nanomatrix formed from the various nanoscale metallic coating layers of metallic coating materials, and are particularly useful in borehole applications.

Suitable core materials include electrochemically active metals having a standard oxidation potential greater than or equal to that of Zn, including as Mg, Al, Mn or Zn or alloys or combinations thereof. For example, tertiary Mg—Al—X alloys may include, by weight, up to about 85% Mg, up to about 15% Al and up to about 5% X, where X is another material. In one embodiment, the material has a substantially uniform average thickness between dispersed particles of about 50 nanometers (nm) to about 5000 nm. In one embodiment, the coating layers are formed from Al, Ni, W or Al2O3, or combinations thereof. In one embodiment, the coating is a multi-layer coating, for example, comprising a first Al layer, a Al2O3 layer and a second Al layer. In some embodiments, the coating may have a thickness of about 25 nm to about 2500 nm. In addition, surface irregularities to increase a surface area of the flapper 32, such as grooves, corrugations, depressions, etc. may be used.

As noted above, the degradation is initiated by exposing the degradable material to a stimulus. In embodiments, the flapper 32 degrades in response to exposure to a fluid. Illustrative fluids include engineered fluids (e.g., frac fluid, acidizing fluid, acid, brine, water, drilling mud, etc.) and naturally occurring fluids (e.g., hydrocarbon oil, produced water, etc.). The fluid used for stimulus may be one or more liquids, one or more gases, or mixtures thereof. In other embodiments, the stimulus may be thermal energy from surrounding formation. Thus, the stimulus may be engineered and/or naturally occurring in the well or wellbore tubular and formation.

The degradable material in the flapper 32 degrades and opens the sub 9 to full-bore flow. The well is allowed to flow up and produce subterranean fluids.

The flapper 32 may also include phenolics, polyvinyl alcohols, polyacrylamide, polyacrylic acids, rare earth elements, glasses (e.g. hollow glass microspheres), carbon, elastic material, or a combination of these materials or above sintered powder compact material. Elastic material herein includes elastomers and means that the flapper 32 can flex. In another embodiment, the flapper 32 may include steel or other non-degradable alloys or composites.

In an embodiment, the sub 9 may include the latch 25 that is connected to the housing 20. The latch 25 may selectively lock the flapper 32 in the open position. The flapper 32 has a degradable material and forms immediate pressure isolation in the closed position. The housing 20 has at least one port 24 sealed by the plug seat 40. The plug seat 40 when shifted, opens the ports 24 to fluid communication.

In another embodiment, the sub 9 may include the latch 25 that is connected to the plug seat 40, and a sliding member 60 connected to the flapper seat 38 by a connector 62. The latch 25 selectively locks the flapper 32 in the open position. The flapper 32 includes a degradable material and forms immediate pressure isolation in the closed position. The housing 20 has at least one port 24 sealed by the sliding member 60. The sliding member 60 when shifted, opens the ports 24 to fluid communication.

The foregoing description is directed to particular embodiments of the present disclosure for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above or embodiments of different forms are possible without departing from the scope of the disclosure. It is intended that the following claims be interpreted to embrace all such modifications and changes.

Claims

1. An apparatus for performing a downhole operation in a wellbore tubular, comprising:

a housing disposed in the wellbore tubular;

a plug seat located inside the housing; and

a flapper and a flapper seat located inside the housing and axially slidable between a first position and a second position in the housing, wherein the plug seat is configured to release the flapper onto the flapper seat when the plug seat is shifted.

2. The apparatus of claim 1, wherein the flapper comprises a degradable material.

3. The apparatus of claim 1, wherein a degradable material is used in at least one of: (i) the flapper seat, (ii) the plug seat, and (iii) a plug.

4. The apparatus of claim 1, wherein the flapper comprises at least one of: (i) ceramic, (ii) steel, (iii) cast iron, and (iv) elastomer.

5. The apparatus of claim 1, wherein the plug seat selectively locks the flapper in the first position.

6. The apparatus of claim 1, further comprising a latch connected to the housing, wherein the latch selectively prevents the flapper from moving to the second position.

7. The apparatus of claim 1, further comprising a sliding member located in the housing, and a connector connecting the sliding member to the flapper seat, wherein the sliding member has at least one port.

8. The apparatus of claim 1, wherein the housing has at least one port sealed by one of the plug seat and a sliding member, and wherein the flapper seat when shifted, opens the at least one port of the housing to fluid communication.

9. The apparatus of claim 1, further comprising a biasing member connected to the flapper wherein the biasing member is at least one of: (i) rotational spring, (ii) a leaf spring, (iii) a cam mechanism, and (iv) an inclined surface of the flapper.

10. The apparatus of claim 1, wherein the flapper forms immediate pressure isolation in the second position.

11. A method for performing a downhole operation in a wellbore tubular, comprising:

disposing a control device in the wellbore tubular, wherein the control device includes: a housing disposed in the wellbore tubular; and a plug seat, a flapper and a flapper seat located inside the housing;

dropping a plug into the wellbore tubular;

allowing the plug to seat on the plug seat;

shifting the plug seat;

releasing the flapper;

rotating the flapper;

seating the flapper on the flapper seat; and

sliding the flapper inside the housing axially.

12. The method of claim 11, further comprising forming pressure isolation between an upper side and the lower side of the flapper immediately after seating the flapper.

13. The method of claim 11, further comprising contacting the flapper with a fluid to degrade the flapper.

14. The method of claim 11, further comprising actuating a downhole tool when the flapper slides axially.

15. The method of claim 11, further comprising treating a subterranean formation by pumping fluids through the wellbore tubular, wherein the treatment includes at least one of: (i) fracturing, (ii) acidizing, (iii) tracer logging, (iv) injection, (v) well cleaning, and (vi) stimulation operation.

16. The method of claim 11, further comprising at least one of: (i) breaking the flapper, and (ii) pumping a degrading fluid into the wellbore tubular to degrade the flapper.