US20160341002A1

Movatterモバイル変換

Info

Publication number: US20160341002A1
Application number: US14/720,082
Authority: US
Inventors: Robert D. McKitrick, III
Original assignee: Baker Hughes Inc
Current assignee: Baker Hughes Holdings LLC
Priority date: 2015-05-22
Filing date: 2015-05-22
Publication date: 2016-11-24

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-actuatedsub9 for hydraulically actuating a downhole tool. The plug-actuatedsub9 includes ahousing20 that encloses theflapper assembly30 and aplug seat40. Theflapper assembly30 is positioned uphole of theplug seat40. Thus, fluid flows from the surface, through theflapper assembly30, and then through theplug seat40. During activation, theflapper assembly30 and theplug seat40 can slide axially in the downhole direction a predetermined distance inside the plug-actuatedsub9. This sliding movement can be used to actuate theflapper assembly30 and perform other functions such as open fluid ports.

In one arrangement, theflapper assembly30 has aflapper32 that has an open position wherein fluid can flow across the plug-actuatedsub9 and a closed position wherein fluid flow is completely blocked and cannot flow across the plug-actuatedsub9. Theflapper assembly30 can have arotational member34, such as a pin or a torsional spring, around which theflapper32 rotates to the closed position. Theflapper assembly30 has aflapper seat38 that has aseating surface37 to form a fluid-tight seal between thehousing20 and theflapper32.

Theplug seat40 is located in thehousing20 and connected to theflapper seat38. Theplug seat40 has aflow bore48 through which fluid flows or other downhole devices can pass. Theplug seat40 also includes asurface44 that can receive aplug50. When theplug50 lands on thesurface44, theplug50 blocks the fluid flow through the flow bore48. In the pre-activated condition, a fasteningmember42, such as shear screws, secures theplug seat40 to thehousing20. During activation, theflapper assembly30 and theplug seat40 move axially, as shown inFIGS. 2 and 3. Thehousing20 has aconstraint29 positioned downhole of theplug seat40 to limit the axial movement of theplug seat40 in the downhole direction. In one non-limiting embodiment, theconstraint29 may be a groove, slot, or profile that receives afitting member46, such as a snap ring.

Thehousing20 has alatch25 to lock theflapper32 in the open position. Thelatch25 can be a protrusion machined, welded or otherwise assembled to thehousing20. Thehousing20 can be positioned along a production string or other wellbore tubular. Thehousing20 is a hollow cylinder that can receive theflapper assembly30 and theplug seat40. Thehousing20 may provide sealing for these components from the wellbore fluids present in the subterranean formation. Thehousing20 may be located in the bottom hole assembly and be threaded to the production string.

In one method of operation, the plug-actuatedsub9 is deployed in a wellbore tubular (not shown). Theflapper32 and theflow bore48 are initially open to allow fluid flow through thesub9 as shown inFIG. 1. Theplug50 is dropped from the surface. Theplug50 lands on thecurved surface44 of theplug seat40 and closes theflow bore48 as shown inFIG. 2. The fluid flow from the surface applies a push force on theplug seat40. Thefastening member42 releases theplug seat40, for example shear screws may be sheared. The fluid shifts theplug seat40 slightly in the downhole direction. Theplug50 and theplug seat40 holds enough pressure to unlatch theflapper assembly30, which is relatively low compared to the necessary force to shift theflapper assembly30. Theflapper assembly30 moves axially with theplug seat40. Therefore, theflapper32 is freed from thelatch25.

FIG. 3 shows theflapper32 seated on theflapper seat38, and theplug seat40 and theflapper assembly30 completely shifted in the downhole direction. The pressure of the fluid pumped from the surface pushes theflapper32 to the closed position and applies a thrusting force on theflapper32 to slide theflapper assembly30 and theplug seat40 toward theconstraint29. Thefitting member46 snaps into the groove of theconstraint29 and axially fixes theplug seat40 with respect to thehousing20. At this point, theflapper32 substantially hydraulically isolates a bore section uphole of theflapper32 and the bore downhole of theflapper32. Thus, the hydraulic pressure uphole of theflapper assembly30 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-actuatedsub9 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-actuatedsub9 into the wellbore tubular. Thesub9 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-actuatedsub9 requires a lower stress on theplug seat40 that is exposed to high fluid pressure when aplug50 seats on thesurface44. The plug-actuatedsub9 that can work with high fluid pressure can receive alarger plug50, and consequently, have a larger flow bore48. If multiple zones and multiple plug actuatedsubs9 are involved, then the plug-actuatedsub9 may be used to meet the need of smaller incremental sizes ofplug seats40 and larger flow bores48.

It should be appreciated that the plug-actuatedsub9 of the present disclosure is subject to various embodiments. In a non-limiting embodiment of the present disclosure, theflapper30 may have a straight or a slim-curved shape. Also, theflapper32 may be located in arecess28 of thehousing20 in the open position. In that case, the inner surface of thelatch25 may be flush with the inner wall of thehousing20.

In some embodiments, one or more devices may be used to assist in closing theflapper32. For instance, thehousing20 may have aninclined surface21 as shown inFIGS. 1-3 facing theflapper assembly30. Theinclined surface21 of thehousing20 pushes theflapper32 to the closed position. Or, a spring such as a bow spring may be used at the back of theflapper32 between thehousing20 and theflapper32. The bow spring can provide the initial push force to close theflapper32. The fluid flow, then, further pushes theflapper32 to the closed position.

Also, thehousing20 may include anadditional member22 to conveniently assemble or insert theflapper assembly30 and theplug seat40 into thehousing20. Theadditional member22 is similar to the housing and may be connected to thehousing20 with a thread or other connection means. First, theflapper assembly30 may be inserted in thehousing20, and theflapper32 may be moved to the open position. Last, theadditional member22 may be placed and theflapper32 may suitably be fastened to thelatch25 that may be located in theadditional member22. In addition, thehousing20 may need features such as grooves may be machined on the inner surface. Closer these features to the opening of thehousing20, the easier is the machining.

In another embodiment and method, theplug seat40 shifts and exposes theports24 of thehousing20 to the flow bore48. A well treatment operation such as fracing may follow to pump frac fluids through theports24. After fracing is completed, the subterranean fluids may flow up the well. The plug-actuatedsub9 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 inFIGS. 4 and 5. The plug-actuatedsub9 may include adownhole member60 affixed to theflapper assembly30. Thedownhole member60 may be a sleeve, slips of a completion or production tool, or any member that uses axial movement during actuation. Thedownhole member60 is affixed to theflapper seat38 by aconnector62 such as a rod or a sleeve. In many respects, the plug-actuatedsub9 ofFIGS. 4 and 5 is similar to that shown inFIGS. 1-3.

As shown inFIG. 4, arestriction member45, such as a protrusion, sleeve or collet, attached to theplug seat40 holds theflapper seat38 at an axially fixed location in thehousing20. Then, theplug50 is dropped in the well, and fluid is pumped to seat theplug50 on theplug seat40. The fluid pushes theplug seat40 in the downhole direction.FIG. 5 shows theflapper seat38aand theflapper32aas freed from therestriction member45 of theplug seat40. When freed, theflapper seat38amay have independent axial movement with respect to theplug seat40. Or, theflapper assembly30 may move with theplug seat40. In either case, because theflapper seat38ais connected to thedownhole member60 by theconnector62, the downhole movement of theflapper assembly30 pulls thedownhole member60 and thereby mechanically actuates the downhole tool.

Astop member36 located on the outer surface of theflapper seat38 may lock theflapper seat38 in the axial direction when theflapper seat38 reaches astop26 of thehousing20. Thestop member36 may be a snap ring, and thestop26 may be a groove. Thestop member36 and thestop26 combination may be replaced with a shoulder or other latch mechanisms. Also, theconstraint29 that limits the movement of theplug seat40 in the downhole direction may also be a shoulder. Or, theconstraint29 may not exist at all.

In one embodiment and method, thedownhole member60 may haveopenings64. Theports24 and theopenings64 are aligned to treat the formation when thestop26 limits the axial downhole movement of theflapper assembly30. Or, thesub9 may be used to create a stroke action to set a downhole tool.

In another embodiment and method, multiple plug-actuatedsubs9 may be set at different depths along a wellbore. Each plug-actuatedsub9 may have incremental sizes of flow bore48 as the plug-actuatedsub9 gets deeper in the well. For instance, oneplug seat40 may have a larger inner diameter than thenext plug seat40 deeper in the well. Therefore, plugs50 may seat at correspondingly sized plug seats40.

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-actuatedsub9 can be formed of a degradable material. For instance, theflapper32 may be partially or totally degradable. For example, the operator may pump fluid downhole to accelerate the degradation of theflapper32.

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 theflapper32, 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, theflapper32 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 theflapper32 degrades and opens thesub9 to full-bore flow. The well is allowed to flow up and produce subterranean fluids.

Theflapper32 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 theflapper32 can flex. In another embodiment, theflapper32 may include steel or other non-degradable alloys or composites.

In an embodiment, thesub9 may include thelatch25 that is connected to thehousing20. Thelatch25 may selectively lock theflapper32 in the open position. Theflapper32 has a degradable material and forms immediate pressure isolation in the closed position. Thehousing20 has at least oneport24 sealed by theplug seat40. Theplug seat40 when shifted, opens theports24 to fluid communication.

In another embodiment, thesub9 may include thelatch25 that is connected to theplug seat40, and a slidingmember60 connected to theflapper seat38 by aconnector62. Thelatch25 selectively locks theflapper32 in the open position. Theflapper32 includes a degradable material and forms immediate pressure isolation in the closed position. Thehousing20 has at least oneport24 sealed by the slidingmember60. The slidingmember60 when shifted, opens theports24 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

What is claimed is:

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 ofclaim 1, wherein the flapper comprises a degradable material.

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

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

6. The apparatus ofclaim 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 ofclaim 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 ofclaim 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 ofclaim 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 ofclaim 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 ofclaim 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 ofclaim 11, further comprising contacting the flapper with a fluid to degrade the flapper.

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

15. The method ofclaim 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 ofclaim 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.