US20150114651A1

US20150114651A1 - Downhole fracturing system and technique

Info

Publication number: US20150114651A1
Application number: US14/063,867
Authority: US
Inventors: John C. Wolf
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2013-10-25
Filing date: 2013-10-25
Publication date: 2015-04-30

Abstract

A system that is usable with a well includes a first tubing string and a plurality of tubing segments. The first tubing string is deployed in the well and includes a plurality of valve assemblies, which span a segment of the first tubing string. The tubing segments are adapted to be deployed in the well inside the first tubing string and attach together in the segment of the first tubing string in a sequence to form a second tubing string in a manner that allows sequential operation of the valve assemblies of the first tubing string.

Description

BACKGROUND

For purposes of preparing a well for the production of oil or gas, at least one perforating gun may be deployed into the well via a conveyance mechanism, such as a wireline or a coiled tubing string. The shaped charges of the perforating gun(s) are fired when the gun(s) are appropriately positioned to perforate a casing of the well and form perforating tunnels into the surrounding formation. Additional operations may be performed in the well to increase the well's permeability, such as well stimulation operations and operations that involve hydraulic fracturing.
When hydrocarbon resources include multiple reservoir intervals, which are either discretely disposed or contained in relatively long production intervals, accessing the reserves may involve fracturing the well at various depths. Thus, the above-described perforating and stimulation operations may be performed in multiple stages of the well.

SUMMARY

The summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
In an example implementation, a technique includes deploying a first tubing string comprising a plurality of valve assemblies in a well; deploying tubing segments inside the first tubing string; and stacking the deployed tubing segments together downhole in the well to construct a second tubing string inside the first tubing string. The stacking is used to sequence operations of the valve assemblies
In another example implementation, a system that is usable with a well includes a first tubing string and a plurality of tubing segments. The first tubing string is deployed in the well and includes a plurality of valve assemblies, which span a segment of the first tubing string. The tubing segments are adapted to be deployed in the well inside the first tubing string and attach together in the segment of the first tubing string in a sequence to form a second tubing string in a manner that allows sequential operation of the valve assemblies of the first tubing string.
In yet another example implementation, an apparatus that is usable with a well includes a tubular housing, at least one connector, a check valve and at least one wiper cup. The tubular housing is adapted to deployed through a lubricator inside a first tubing string and descend untethered to a downhole location of the well to form a segment of a second tubing string. The connector(s) attach the tubular housing to another segment of the second tubing string downhole in the well. The check valve restricts fluid communication within a central flow path of the tubular housing. The wiper cup(s) form an annular seal between the tubular housing and the first tubing string.
Advantages and other features will become apparent from the following drawings, description and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of a well having a liner string with fracturing valve assemblies according to an example implementation.

FIGS. 2A, 2B and 2C are schematic diagrams of the well of FIG. 1 illustrating a sequence of multiple stage fracturing operations according to an example implementation.

FIG. 3 is a flow diagram depicting a technique to deploy tubing segments in an outer tubing string to sequentially open valve assemblies of the outer tubing string according to an example implementation.

FIGS. 4A and 4B collectively depict a flow diagram of a technique to perform multiple stage fracturing operations according to an example implementation.

FIG. 5 is a partial cross-sectional view of a bottom hydraulic fracturing valve assembly of the liner string of FIG. 1 according to an example implementation.

FIGS. 6, 7, 8 and 9 are perspective views of bottomhole assemblies of a fracturing system according to an example implementation.

FIG. 10 is a partial cross-sectional view of a tubing anchor latch of a bottomhole assembly according to an example implementation.

FIG. 11 is a partial cross-sectional view of an upper tubing connector of a bottomhole assembly according to an example implementation.

FIG. 12 is a partial cross-sectional view of a lower tubing connector of a bottomhole assembly according to an example implementation.

FIG. 13 is a partial cross-sectional view of a check valve assembly according to an example implementation.

FIG. 14 is a partial cross-sectional view of a blast joint according to an example implementation.

FIG. 15 is a partial cross-sectional view of a fracturing valve assembly according to an example implementation.

FIG. 16 is a partial cross-sectional view of a tubing cup tool according to an example implementation.

FIG. 17 is a partial cross-sectional view of a shiftable ported valve assembly according to an example implementation.

FIG. 18 is a partial cross-sectional view illustrating landing of the tubing cup tool of FIG. 16 inside the fracturing valve assembly of FIG. 15 for a closed state of the fracturing valve assembly according to an example implementation.

FIG. 19 is a partial cross-sectional view illustrating landing of the tubing cup tool of FIG. 16 in the fracturing valve assembly of FIG. 5 for an open state of the fracturing valve assembly according to an example implementation.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of features of various embodiments. However, it will be understood by those skilled in the art that the subject matter that is set forth in the claims may be practiced without these details and that numerous variations or modifications from the described embodiments are possible.
As used herein, terms, such as “up” and “down”; “upper” and “lower”; “upwardly” and downwardly”; “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments. However, when applied to equipment and methods for use in environments that are deviated or horizontal, such terms may refer to a left to right, right to left, or other relationship as appropriate.
Systems and techniques are disclosed herein for purposes of performing fracturing operations in multiple zones, or stages, of a well, without the use of conventional deployment mechanisms, such as a wireline or a coiled tubing, to intervene in the well to operate fracturing valves. Moreover, the systems and techniques that are disclosed herein may be used in cased hole completions as well as in open hole completions.
As a more specific example, FIG. 1 depicts an example well 100, which includes a lateral wellbore 110 that extends through one or more zones, or stages, of the well 100. For the example of FIG. 1, the lateral wellbore 110 extends from a main wellbore 102, which may be cased by a casing string 104, as depicted in FIG. 1. Moreover, for the example of FIG. 1, the lateral wellbore 110 is an open hole completion in which a liner string 120 extends through the stage(s) through which the wellbore 110 extends.
For this example, the liner string 120 has an upper packer 122 as well as one or more additional packers 123, which are radially expanded, or set, for purposes of forming isolated stages associated with a wellbore 110. The packer 122, 123 may be a mechanically-set packer, a weight-set packer, a hydraulically-set packer, a swellable material-based packer, a bladder-based packer, and so forth, as can be appreciated by the skilled artisan.
In accordance with example implementations, the liner string 120 contains a bottom hydraulic fracturing sub, or valve assembly 130, as well as additional fracturing subs, or valve assemblies 140 (N fracturing valve assemblies 140-1. . . 140-N, being depicted as examples in FIG. 1) that are disposed above the assembly 130. In this manner, as further described herein, the fracturing valve assemblies 130 and 140 are run into the well as part of the liner string 120 in respective closed states (i.e., in states to block fluid communications between the central passageway of the liner string 120 and the regions outside of the valve assemblies 130 and 140). After the liner string 120 is installed and the fracturing is to begin, the fracturing valve assemblies 130 and 140 are sequentially opened beginning with a toe end 160 of the wellbore 110 and ending near the heel end 122 of the wellbore 110. As each fracturing valve assembly 130, 140 is opened, one or more surface pumps 110 at an earth surface E of the well 100 may pump fluid 112 into the well, which is routed to the central passageway of the liner string 120 and into the stage associated with the opened valve 130, 140 for purposes of forming a respective fracturing network.
It is noted that in further implementations, the liner string 120 may be replaced with a casing string (i.e., a string that lines and supports the wellbore 110), which is cemented in the wellbore 110 and contains casing-conveyed fracturing valve assemblies in place of the valve assemblies 130 and 140. Thus, many variations are contemplated, which are within the scope of the appended claims.
It is noted that the well 100 may be a terrestrial well or a subsea well, depending on the particular implementation. Moreover, although a lateral wellbore 110 is specifically disclosed herein to illustrate fracturing systems and techniques, it is understood that in accordance with further implementations, the techniques and systems that are disclosed herein may likewise be applied to vertically-extending or, in general, non-lateral wellbores.
Instead of using a conventional deployment mechanism, such as a coiled tubing string or wireline, in an intervention to operate the fracturing valve assemblies, as disclosed herein, the fracturing valve assemblies 140 are sequentially opened by deploying tubing segments into the central passageway of the liner string 120. In this manner, the deployed tubing segments each have a sufficiently small length (a length of 25 feet or less, as an example) to allow the segment to pass through Earth surface-disposed lubricator 108 of the well 100. The deployed tubing segments may be guided into the liner string 120 via a whipstock 106 in the main wellbore. In further example implementations, the well may be a multi-stage stimulation well that does not include a whipstock. The tubing segments are further constructed so that the first deployed tubing segment anchors to the bottom hydraulic fracturing valve assembly 130 and the remaining deployed tubing segments attach end-to-end for purposes of forming an inner string within the liner string 120.
As the tubing segments are stacked together and assembled downhole inside the liner string 120, the tubing segments form central passageway and annular seals within the liner string 120 that permit the sequential operation of the fracturing valve assemblies 140, as further disclosed herein. At the conclusion of the multiple stage fracturing operations that the inner tubing string may be subsequently used as a production tubing string to receive produced well fluid from the fractured stages.
As a more specific example, the above-described multiple stage fracturing operations may begin by first opening the bottom hydraulic fracturing valve assembly 130 and using the assembly 130 to form a bottom fracture zone 200 that is illustrated in FIG. 2A. More specifically, in accordance with example implementations, the bottom hydraulic fracturing valve assembly 130 is constructed to respond to pressure inside the central passageway of the liner string 120 that exceeds a predetermined threshold.
Initially, the fracturing valve assemblies 140 are all closed. Therefore, by pumping fluid into the central passageway of the liner string 120, hydraulic pressure inside the central passageway may be increased to cause the valve assembly 130 to open its radial ports and establish fluid communication between the central passageway of the liner string 120 and the region that is outside of the valve assembly 130. As a more specific example, in accordance with example implementations, the valve assembly 130 may be a tubing pressure-operated sleeve valve assembly. At the conclusion of the communication of fracturing fluid (a mixture of proppant and a carrier fluid, for example) to create the fractured zone 200, operations then proceed to operate the next, adjacent fracturing valve assembly 140-1.
More specifically, referring to FIG. 2B, a first tubing segment 210-1 is deployed through the lubricator 108 and pumped into the liner string 120 until the tubing segment 210-1 lands in and is attached, or anchored, to the bottom hydraulic fracturing valve assembly 130. As explained further herein, the tubing segment 210-1 is the first of many tubing segments 210 that may be deployed into the liner string 120. As described further herein in connection with FIGS. 11 and 12, each tubing segment 210 is constructed to form a latched connection with the tubing segment 210 below (except for the tubing segment 210-1, which anchors to the assembly 10) and the tubing segment 210 above (except for the uppermost segment 210). Thus, the tubing segments 210 are collectively stacked together inside the liner string 120 to form an inner string. As the tubing segments 210 are stacked together, the tubing segments 210 form annular seals and passageway restrictions at the appropriate intervals so that a fluid pressure may be applied against these seals and restrictions to open the fracturing valve assemblies 140. Thus, the process of stacking of the tubing segments 210 inside the liner string 120 may be interrupted at various points to for purposes of pressuring fluid to opening the fracturing valve assemblies 140.
For example, the stacking of the tubing segments 210 ceases near the fracturing valve assembly 140-1. As discussed further herein and illustrated in FIGS. 18 and 19, due to a fluid restriction (check valve, for example, as described herein) inside the tubing segments 210 and an annular seal outside of the tubing segments (a cup seal, for example, as described herein), fluid may be pumped into the well to pressurize a piston surface of the fracturing valve assembly 140-1 for purposes of opening the radial ports of the assembly 140-1. Fluid may continue to be pumped, which flows through the radial ports of the assembly 140-1 to form a second fracture zone 220.
Each tubing segment 210 may be formed from one or multiple bottomhole assemblies (BHAs), which are described herein.
In general, the above-described process may be repeated by deploying additional tubing segments 210 into the liner string 120, stacking the tubing segments 210 end-to-end together and forming corresponding seals that allow the corresponding sequential operation of other valve assemblies 140.
Referring to FIG. 2C, thus, at the conclusion of the fracturing operations, a tubing segment 210-N configures the uppermost fracturing valve assembly 140-N to be open to form a corresponding fracture zone 230. At this point, the deployed and now connected tubing segments 210 form an inner string (a production tubing string, for example) inside the liner string 120.
Thus, referring to FIG. 3, in accordance with example implementations, a technique 300 includes deploying (block 302) a first tubing string containing valve assemblies into a well and deploying (block 304) tubing segments inside the first tubing string. Pursuant to the technique 300, the deployed segments are stacked together (block 306) downhole in the well to construct a second tubing string. The stacking process may be used, pursuant to block 308, to sequence the opening of the valve assemblies.
As a more specific example, FIG. 5 depicts the bottom hydraulic fracturing valve assembly 130, in accordance with an example implementation. It is noted that FIG. 5, as well as additional figures of the present application, depict partial cross-sectional views. In this regard, FIG. 5, for example, depicts an upper cross section of the valve assembly 130 relative to a longitudinal axis 500 of the liner string 120, with it being understood that the lower cross section of the assembly 130 may be derived by mirroring the upper cross section about the longitudinal axis 500.
In general, the bottom hydraulic fracturing valve assembly 130 includes a tubular housing 504 that is concentric with the longitudinal axis 500. The housing 504 contains radial ports 510 and an inner sleeve 530 that is concentric with the longitudinal axis 500 and controls fluid communication through the radial ports 510.
More specifically, FIG. 5 depicts the valve assembly 130 in its run-in-hole state. In this state, the inner sleeve 530 blocks fluid communication between the central passageway of the valve assembly 130 and the radial ports 510. As depicted in FIG. 5, seal elements 511 and 513 form seals between the inner surface of the housing 504 and the outer surface of the sleeve 530. Moreover, the sleeve 530 is retained in its initial position to close fluid communication through the ports 510 via one or more shear pins 531.
Fluid inside the central passageway of the liner string 120 causes the inner sleeve 530 to shift, or translate, along the longitudinal axis 500 to open the valve assembly 130 to therefore allow fluid flow through the radial ports 510. A ratchet sleeve 532 engages ratchet teeth 533 formed on the outer surface of the sleeve 530, in accordance with example implementations, to secure the valve assembly 130 in the open state.
Among its other features, in accordance with example implementations, the valve assembly 130 includes pin threads 520 at its lower end to form a corresponding tubing connection and box threads 544 at its upper end to form a corresponding connection to the upper portion of the liner string 120. The valve assembly 130 further includes an interior anchor latch profile 542 that is formed in the interior surface of the housing 504 for purposes of engaging a latch of a bottom hole assembly (i.e., a tubing segment) as further disclosed herein. Moreover, in accordance with example implementations, the inner surface of the housing 504 further includes a seal bore 540 for purposes of engaging seals of the bottom hole assembly.
As a more specific example, each tubing segments 210 that is deployed in the liner string 120 may contain one or more of the following bottom hole assemblies (BHAs). In this manner, referring to FIG. 6, in accordance with example implementations, a first BHA 600 may be deployed in the liner string 120 after the fracture zone 200 is formed. The first BHA 600 includes a tubing anchor latch 604 near its lower end for purposes of engaging the anchor latch profile 542 (see FIG. 5) of the bottom hydraulic fracturing valve assembly 130 and anchoring the first BHA 600 to the valve assembly 130.
The first BHA 600 further includes a lower seal bore connector 602 for purposes of extending into the bottom hydraulic fracturing valve assembly 130 and forming a seal with the seal bore 540 of the assembly 130. In general, the BHA 600 may be formed from a tubular housing 608 that is concentric with a longitudinal axis 601 of the BHA 600. At its upper end, the first BHA 600 includes an upper tubing connector 612 that connects to the next deployed tubing segment.
For purposes of aiding pumping of the first BHA 600 into the liner string 120, in accordance with example implementations, the first BHA 600 includes a pump down ring 610 near its upper end. Moreover, uphole from the pump down ring 610, the first BHA 600 may include a seal bore 614 to form a corresponding fluid seal with the adjacent uphole tubing segment as well as a ratchet profile 620 to secure the connection with this tubing segment, as further disclosed herein.
Thus, the first BHA 600 may be, in accordance with example implementations, the first tubing segment that is deployed through the lubricator 108 (FIG. 1) and into the liner string 120.
In accordance with example implementations, the next tubing segment that is deployed into the liner string may be a second BHA 700 that is depicted in accordance with FIG. 7. In this manner, referring to FIG. 7, the second BHA 700 is formed from a tubular housing 706 that is generally concentric with the longitudinal axis 601. The second BHA 700 includes a lower tubing connector 702 that is constructed to form a corresponding sealed and mated connection with the upper tubing connector 612 of the first BHA 600. The second BHA 700 further includes an upper tubing connector 612 that is constructed to form a sealed and mechanical connection to the next tubing segment.
In general, the function of the second BHA 700 is to serve as a spacer between the first BHA 600 and a third BHA 800 (described below in connection with FIG. 8) that forms the seals with the first valve assembly 140-1 for purposes of operating this assembly 140-1. In general, the length of a given BHA, such as the first BHA 600 or the second BHA 700, may be limited by the lubricator 108 (see FIG. 1, for example). Therefore, one or multiple second BHAs 700 may be deployed into the liner string 120 for purposes of establishing the appropriate spacing between the first BHA 600 that anchors the inner string to the liner string 120 and the third BHA 800.
Referring to FIG. 8, the third BHA 800 forms the flow restriction and annular seal for purposes of operating the lowermost fracturing valve assembly 140-1 (see FIG. 1, for example). In this regard, the third BHA 800, in accordance with example implementations, is formed from a tubular housing 810 that is generally concentric with the longitudinal axis 601. The third BHA 800 includes a lower tubing connector 702 that is constructed to form a sealed and mechanical connection with the upper tubing connector 612 of either the first BHA 600 or second BHA 700, depending on the particular implementation.
The third BHA 800 further includes an upper ratchet profile 826 and seal nose 828 for purposes of forming a corresponding mechanical and sealed connection with a fourth BHA 900 (as described below in connection with FIG. 9) that is deployed in the liner string 120 above the third BHA 800, as further disclosed below. The third BHA 800 includes a check valve assembly 804 that establishes a directional flow through the BHA 800. More specifically, in accordance with example implementations, the check valve assembly 804 permits an uphole flow but prevents a downhole flow. Thus, the check valve assembly 804 allows for a fluid column to be established uphole of the assembly 804 for purposes of permitting the fluid column to be pressurized to actuate the lowermost valve assembly 140-1. The check valve assembly 804 further permits a flow of the production fluid from the well at the conclusion of the multiple stage fracturing operations.
Among its other features, the third BHA 800 includes a cup tool 820, which forms an annular seal between the exterior of the tubular housing 810 and the interior of the liner string 120. More specifically, as further described herein, the annular seal is formed at the appropriate position inside or slightly below the lowermost fracturing valve assembly 140-1 to allow pressure to actuate the assembly's sleeve valve to shift the assembly 140-1 open.
In accordance with example implementations, the third BHA 800 includes a blast joint 824 that is disposed uphole of the cup tool 820. In general, the blast joint 824 is positioned to span the region inside the radial ports of the lowermost fracturing valve assembly 140-1. As its name applies, the blast joint 824 provides a degree of erosion protection for the third BHA 800.
Referring to FIG. 9, the fourth BHA 900 is landed in proximity to the fracturing valve assemblies 140-2. . . 140-N for purposes of opening these valve assemblies. In this regard, between any two of the valve assemblies 140-2 to 140-N, one or more second BHAs 700 may first be deployed with the last BHA being the fourth BHA 900. The fourth BHA 900, in general, has a design that is similar to the third BHA 800, except that the fourth BHA 900 includes a shiftable ported sub, or shiftable valve assembly 910, which may be used for purposes of controlling the flow of production fluid from a particular stage of the well.
In this regard, the fourth BHA 900 is deployed downhole with its shiftable ported valve assembly 910 closed, and the assembly 910 remains closed during the fracturing operations. Subsequently, a shifting tool, for example, may be deployed inside the inner tubing string to open the various assemblies 910, as well as selectively close certain assemblies 910 for purposes of isolating regions of the well in which production is not desired, such as, for example, regions of the well in which an excessive amount of water is being produced. In addition to the shiftable ported valve assembly 910, the fourth BHA 900 has a tubular housing 904 that is concentric with the longitudinal axis 601; and the BHA 900 contains a check valve 804, a cup tool 820, a blast joint 824, a ratchet profile 826 and a seal 828, similar to the third BHA 800. Moreover, the fourth BHA 900 includes a lower tubing connector 702.
Thus, in accordance with example implementations, the following BHAs are used for the various stages. At least two BHAs are used in the first (bottommost) stage; and at least one BHA is used in the subsequent stages, depending on the valve assembly-to-valve assembly spacing. More specifically, the first stage between the lowermost hydraulic fracturing valve assembly 130 and the fracturing valve assembly 140-1 includes two or more BHAs, depending on the spacing between the valve assemblies 130 and 140-1: the first BHA 600 at the bottom of the stage; the third BHA 800 at the top of the stage; and zero, one or more than one second BHA 700 between the first BHA 600 and the third BHA 800. Each of the other stages (i.e., the stages between fracturing valve assemblies 140) includes one or more BHAs, depending on the spacing between adjacent valve assemblies 140: zero, one or more than one second BHA 700 at the bottom of the stage; and one fourth BHA 900 at the top of the stage.
To summarize, a technique 400 that is depicted in FIGS. 4A and 4B may be used in accordance with example implementations. Referring to FIG. 4A, pursuant to the technique 400, a bottom hydraulic fracturing valve assembly of a liner string is opened (block 402) and the corresponding stage is fractured by communicating fracturing fluid via the opened bottom fracturing valve assembly, pursuant to block 404. Next, the first BHA of the inner string is deployed into the liner string, pursuant to block 406. Next, one or more second BHAs are deployed, pursuant to block 408. Subsequently, a third BHA is deployed, pursuant to block 410. The first fracturing valve assembly uphole of the bottom hydraulic fracturing valve assembly may then be opened, pursuant to block 412, so that the second stage may be fractured by communicating fluid through the first fracturing valve assembly, pursuant to block 414.
Referring to FIG. 4B, next, one or more second BHAs may be deployed into the liner string, pursuant to block 416 and then the fourth BHA is deployed into the liner string, pursuant to block 418. The next fracturing valve assembly of the liner string may then be opened (block 420) so that the corresponding stage may be fractured (block 422). Blocks 416, 418, 420 and 422 may then be repeated of the additional valve assemblies. In this regard, if a determination (decision block 422) is made that another stage is to be fractured, control returns to block 416.
Referring to FIG. 10, in accordance with example implementations, the tubing anchor latch 604 has a tubular housing 1000 that is concentric about the longitudinal axis 601. The latch 604 includes a seal stack 1002 that is disposed on the outside of the tubular housing 1000 for purposes of forming a seal between the tubing anchor latch 604 and the seal bore 540 of the bottom hydraulic fracturing valve assembly 130 (see FIG. 5). The tubing anchor latch 604 further includes an anchor snap latch 1004 that is constructed to engage the anchor latch profile 542 (see FIG. 5) of the bottom fracturing valve assembly 130. Moreover, in accordance with example implementations, the tubing anchor latch 604 includes a tubing box thread 1014 for purposes of securing the tubing anchor latch 604 to the remainder of the first BHA 600.
Referring to FIG. 11, in accordance with example implementations, the upper tubing connector 612, such as, for example, the upper tubing connector 612 of the first and second BHAs 600 and 700, includes a tubular housing 1100 and one or multiple radially-extending centralizers 1104 that extend therefrom. The upper tubing connector 612 further includes a pump down ring 610 (an elastomer ring, for example), which circumscribes the tubular housing 1100 and may be secured in place by a pump down ring retaining nut 1110. As further depicted in FIG. 11, among its other features, the upper tubing connector 612 may include a ratchet profile 620 for purposes of engaging an adjacent BHA disposed above the connector 612 as well as a seal nose 614 for purposes of providing a smooth surface for forming a corresponding fluid seal with the BHA. Moreover, the upper tubing connector 612 includes a box thread 1101 for purposes of forming a corresponding mechanical and sealed connection with the downhole components of the associated BHA.
Referring to FIG. 12, in accordance with example implementations, the lower tubing connector 702 of the second 700, third 800 and fourth 900 BHAs includes a generally tubular housing 1202 that includes a box thread 1230 for purposes of forming mechanical and fluid seal connections with the remainder of the associated BHA. Moreover, a seal stack 1224 is disposed inside the tubular housing 1202 for purposes of forming a sealed connection with the corresponding seal nose of the inserted BHA. As depicted in FIG. 12, the lower tubing connector 702 includes a ratchet ring 1220 for purposes of forming a ratchet connection with the corresponding ratchet profile of the inserted BHA. The ratchet ring 1220 may be held in place by a corresponding ratchet ring 1208. Moreover, among its other features, the lower tubing connector 702 may include radially extending centralizers 1204, in accordance with example implementations.
Referring to FIG. 13, in accordance with example implementations, the check valve assembly 804 may be formed from a generally tubular housing 1320 that is concentric about the longitudinal axis 601. In general, the check valve assembly 804 includes an inner box thread 310 at its upper end and an inner box thread 1304 at its lower end for purposes of coupling the check valve assembly 804 in line with the remaining components of the BHA. The check valve assembly 804 includes an interior valve seat 1324 that is formed on the interior surface of the housing 1320 for purposes of receiving a ball 1308 to prevent fluid flow in the downhole direction. In this regard, when the ball 1308 is seated in the seat 1324 in response to pressure uphole of the ball 1308, fluid flow through the central passageway of the check valve assembly 804 is prevented.
The check valve assembly 804 further includes an interior sleeve 1330 that has a corresponding opening 1334 to receive the ball 1308 when pressure from downhole of the ball 1308 pushes the ball 1308 into the seat 1334. Due to the annular clearance between the seat 1330 and the interior of the tubular housing 1320 and the radial ports 1336 of the sleeve 1330, fluid directed uphole is communicated around the ball 1308 and is allowed to flow through the check valve assembly 804. Thus, produced well fluid may flow uphole through the check valve assembly 804.
In accordance with example implementations, the ball 1308 may be constructed from one or more dissolvable materials. In this regard, the ball 1308 may degrade or oxidize over time such that eventually one or more parts of the ball 1308 disintegrate to the extent that allows the ball 1308 to pass out of the check valve assembly 804. This may be beneficial after completion of the fracturing operations open up the interior of the inner string for interventions.
As a more specific example, in accordance with example implementations, the ball 1308 may be formed from a degradable/oxidizable material, which retains its structural integrity for the fracturing operations. However, over a longer time (a week or a month, as examples), the degradable/oxidizable material(s) of ball 1038 may sufficiently degrade in the presence of wellbore fluids to cause a partial or total collapse of the fluid barrier presented by the ball 1308. In accordance with example implementations, dissolvable or degradable alloys may be used similar to one or more of the alloys that are disclosed in the following patents: U.S. Pat. No. 7,775,279, entitled, “Debris-Free Perforating Apparatus and Technique,” which issued on Aug. 17, 2010; and U.S. Pat. No. 8,211,247, entitled, “Degradable Compositions, Apparatus Compositions Comprising Same, And Method of Use,” which issued on Jul. 3, 2012.
Referring to FIG. 14, in accordance with example implementations, the blast joint 824 may include a tubular housing 1410 that is generally concentric with the longitudinal axis 601. The tubular housing 1410 includes an increased diameter section 1411 to provide a thicker, fluid corrosion-resistant, section of the blast joint 824 that coincides with the position of the ports of the fracturing valve assembly 140. As depicted in FIG. 14, at its upper end, the blast joint 824 may include a ratchet profile 826 and seal nose 828 for engaging the lower tubing connector of the adjacent BHA, and the blast joint 824 may include a pin thread 1404 for purposes of forming a mechanical and fluid seal with the downhole part of its associated BHA.
FIG. 15 depicts the fracturing valve assembly 140, in accordance with example implementations. In general, the fracturing valve assembly 140 is formed from a tubular housing 1520 that is generally concentric with the longitudinal axis 500 of the liner 120. The tubular housing 1520 includes radial ports 1540, and an inner sleeve 1518 is disposed inside the tubular housing 1520 for purposes of controlling the communication of the fluid through the radial ports 1540. In this regard, seals 1504 and 1505 may be disposed at the lower and upper ends, respectively, of the inner sleeve 1518 for purposes of blocking flow through the radial ports 1540 in the closed state of the fracturing valve assembly 140.
In accordance with example implementations, the fracturing valve assembly 140 includes a ratchet sleeve 1552 that engages a corresponding shifting profile 1554 on the outer surface of the inner sleeve 1518 for purposes of retaining the fracturing valve assembly 140 in the open state after the assembly 140 is opened. Moreover, as depicted in FIG. 15, in accordance with example implementations, a shifting profile 1550 may be formed in the interior surface of the inner sleeve 1518 for purposes of allowing the sleeve 1518 to be engaged by a shifting tool to selectively manipulate the open or closed state of the valve assembly 140 via the use of the tool.
Referring to FIG. 16, in accordance with example implementations, the tubing cup tool 820 includes a generally tubular housing 1608 that is concentric with the longitudinal axis 601. The tubing cup tool 820 includes box threads 1604 and 1606 at its lower and upper ends, respectively, for purposes of coupling the tubing cup tool 820 in line with the remaining components of the BHA. In general, the tubing cup tool 820 includes high pressure high temperature (HPHT) wiper cups 1610 and 1614 that circumscribe the tubular housing 608 and are constructed to form respective annular seals between the BHA and the interior surface of the liner string 120.
Referring to FIG. 17, in accordance with example implementations, the shiftable ported valve assembly 910 includes lower 1702 and upper 1704 box threads for purposes of coupling the assembly 910 in line with the remaining components of the BHA. In general, the shiftable ported valve assembly 910 includes a generally tubular housing 1705, which includes radial ports 1740 for communicating fluid between the central passageway of the assembly 910 and the region outside of the housing 1705.
The shiftable ported valve assembly 910 further includes an inner sleeve 1720 that has a corresponding inner profile 1721, which is constructed to be engaged by a shifting tool for purposes of transitioning the valve assembly 910 between its open and closed states. The state of the shiftable ported valve assembly 910 depicted in FIG. 17 is the open state in which bonded seals 1730 and 1731 disposed on the outside of the inner sleeve 1720 are translated away from the radial ports 1740 to allow fluid communication through the ports 1740. However, the inner sleeve 1720 may be translated uphole to dispose the seals 1730 and 1731 on either side of the ports 1740 to block fluid communication and thus, transition the valve assembly 910 into its closed state.
As depicted in FIG. 17, in accordance with example implementations, the inner sleeve 1720 may be connected to a collet 1709 that engages a corresponding collet profile 1710 that is formed in the interior surface of the outer housing 1705 when the valve assembly 910 is in its closed state for purposes of securing, or retaining, the valve assembly 910 in this closed state. An upward shifting force via a shifting tool engaging the shifting profile 1721, however, may be used to disengage the collet 1709 from the profile 1710 to allow the valve assembly 910 to be closed.
FIG. 18 is an illustration 1800 depicting the landing of the tubing cup tool 820 inside the fracturing valve assembly 140. For this example, the valve assembly 140 is in its closed state. As shown, the cup tool 820 forms an annular seal that allows hydraulic pressure to be exerted on the inner sleeve 1518. Therefore, upon exertion of sufficient fluid pressure, the inner sleeve 720 may be shifted downhole, as depicted in an illustration 1900 of FIG. 19. Referring to FIG. 19, thus, the shifting of the sleeve 1518 opens fluid communication through the radial ports 1540.
While a limited number of examples have been disclosed herein, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations.

Claims

What is claimed is:

1. A method comprising:

deploying a first tubing string comprising a plurality of valve assemblies in a well;

deploying tubing segments inside the first tubing string;

stacking the deployed tubing segments together downhole in the well to construct a second tubing string inside the first tubing string; and

using the stacking to sequence operations of the valve assemblies.

2. The method of claim 1, wherein the using comprises opening the valve assemblies one at a time and in response to opening each valve assembly communicating fluid through the assembly to fracture a region of the well.

3. The method of claim 1, wherein the first tubing string further comprises a bottom valve assembly disposed below the plurality of valve assemblies, the method further comprising:

before the deploying of the tubing segments begins, opening the bottom valve assembly and communicating fluid through the bottom valve assembly to fracture a region of the well.

4. The method of claim 3, wherein deploying the tubing segments comprises deploying a set of at least one segment of the tubing segments to anchor the set to the bottom valve assembly, form an annular seal between the set and the first tubing string and restrict flow through the set to a single flow direction.

5. The method of claim 4, further comprising:

using the annular seal and the flow restriction to open one of the valve assemblies of the plurality of valve assemblies.

6. The method of claim 1, wherein deploying the tubing segments comprises deploying a set of at least one segment of the tubing segments to restrict flow between two of the valve assemblies to a single direction and form an annular seal between the set and the first tubing string.

7. The method of claim 6, further comprising:

using the annular seal and the flow restriction to open one of the valve assemblies of the two valve assemblies.

8. The method of claim 1, further comprising:

using the second tubing string as a production tubing string.

9. The method of claim 8, wherein deploying the tubing segments comprises deploying at least one tubing segment comprising a ported valve assembly to selectively isolate a region of the well from hydraulic communication with the production tubing string.

10. The method of claim 1, wherein:

the first tubing string further comprises a bottom valve assembly disposed below the plurality of valve assemblies,

the deployed tubing segments comprise a first bottom hole assembly, second bottom hole assemblies and a third bottom hole assembly; and

the deploying and stacking comprises:

deploying the first bottom hole assembly and anchoring the first bottom hole assembly to the bottom valve assembly;

deploying at least one of the second bottom hole assemblies based on a spacing between the bottom valve assembly and a lowermost valve assembly of the plurality of valve assemblies;

deploying the third bottom hole assembly to restrict flow between the lowermost valve assembly of the plurality of valve assemblies and the third bottom hole assembly to a single direction and form an annular seal between the third bottom hole assembly and the first tubing string.

11. The method of claim 10, wherein:

using the flow restriction and the annular seal to open the lowermost valve assembly of the plurality of valve assemblies.

12. The method of claim 11, wherein:

the deploying and stacking further comprises:

deploying at least one additional second bottom hole assembly of the second bottom hole assemblies based on a spacing between the lowermost valve assembly and the adjacent valve assembly of the plurality of valve assemblies uphole from the lowermost valve assembly;

deploying a fourth bottom hole assembly to restrict flow between the adjacent valve assembly of the plurality of valve assemblies and the fourth bottom hole assembly to a single direction, form an annular seal between the fourth bottom hole assembly and the first tubing string, and allow selective fluid communication between a region outside the second tubing string and an interior flow path of the second tubing string.

13. A system usable with a well, comprising:

a first tubing string to be deployed in the well and comprising a plurality of valve assemblies spanning a segment of the first tubing string; and

a plurality of tubing segments, wherein the tubing segments are adapted to:

be deployed in the well inside the first tubing string; and

attach together in the segment of the first tubing string in a sequence to form a second tubing string in a manner that allows sequential operation of the valve assemblies of the first tubing string.

14. The system of claim 13, wherein the second tubing string comprises a production tubing string.

15. The system of claim 13, wherein the plurality of valve assemblies comprises ports to communicate a fracturing fluid.

16. The system of claim 13, wherein the first tubing string comprises a liner string or a casing string.

17. An apparatus usable with a well, comprising:

a tubular housing adapted to deployed through a lubricator inside a first tubing string and descend untethered to a downhole location of the well to form a segment of a second tubing string;

at least one connector to attach the tubular housing to another segment of the second tubing string downhole in the well;

a check valve to restrict fluid communication within a central flow path of the tubular housing; and

at least one wiper cup to form an annular seal between the tubular housing and the first tubing string.

18. The apparatus of claim 17, further comprising a ported valve assembly to be selectively operated to regulate fluid communication between the central flow path of the tubular housing and a region outside of the housing.

19. The apparatus of claim 17, further comprising a seal nose to form a seal between the central flow path and the central flow path of the another segment of the second tubing string.

20. The apparatus of claim 17, further comprising a ratchet teeth to engage a ratchet sleeve of the another segment of the second tubing string.