LATERAL COMPLETION SYSTEM WITH RETRIEVABLE INNER LINER

Abstract

A dual liner assembly for a multilateral fracking system, comprises a junction support liner adapted to be installed in a lateral wellbore at a junction with a main wellbore; an inner liner with an upper portion and a lower portion, the inner liner being positioned inside the junction support liner and extending beyond the junction support liner within the main wellbore and within the lateral wellbore when the assembly is installed; and a cut and release connector adapted to join the inner liner and the junction support liner and to enable detaching of the upper portion of the inner liner from the assembly. A method of multilateral fracking is also described.

Description

RELATED PATENT APPLICATIONS

This patent application is based on Provisional Patent Application Ser. No. 62/420,363, filed Nov. 10, 2016 the content of which is hereby incorporated by reference in its entirety.

FIELD

The specification is directed to recovery of hydrocarbons from subterranean oil formations and particularly to a multilateral supported junction with double liner.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawings accompanying and forming part of this specification are included to depict certain aspects of the invention. A clearer impression of the invention, and of the components and operation of systems provided with the invention, will become more readily apparent by referring to the exemplary, and therefore non-limiting, embodiments illustrated in the drawings, wherein identical reference numerals designate the same components. Note that the features illustrated in the drawings are not necessarily drawn to scale.

Several aspects of the present invention are illustrated by way of example, and not by way of limitation, in detail in the figures, wherein:

FIG. 1 is a schematic illustration of a section through a well showing a wellbore junction of a main wellbore and a lateral wellbore.

FIG. 2a (corresponding to FIG. 6a of U.S. Pat. No. 9,644,459) is a schematic illustration of a liner running tool installing a liner in a lateral wellbore.

FIG. 2b (corresponding to FIG. 4 of U.S. Pat. No. 5,477,925) shows another way of providing a cased lateral borehole through a window.

FIG. 3 is a diagrammatic representation of a dual liner assembly for a multilateral fracking system.

FIG. 4 is a diagrammatic representation of a dual liner assembly installed in a lateral wellbore.

FIG. 5 is a diagrammatic representation of another embodiment of a dual liner assembly.

FIG. 6 is a diagrammatic representation of cutting a dual liner assembly.

FIG. 7 is a diagrammatic representation of cutting a dual liner assembly with an upper portion removed.

FIG. 8 is a diagrammatic representation of another embodiment of a dual liner assembly.

BACKGROUND

Most wellbores are drilled with deviated or horizontal wells that extend through different production zones from a main wellbore. Typically, lateral wellbores are drilled and accessed from a window formed in the casing of the main wellbore. Then, liners are run into the lateral wellbores and connected to the main wellbore, the lateral wellbores are accessed through the window, and then the zones are fracked using perforating devices or hydraulic pressurization. Sometimes a window opening is pre-formed in the casing and sometimes the window opening is formed entirely by drilling out from the main wellbore through the casing and cement (if any) through the borehole wall and outward therefrom.

However, interconnecting such lateral wellbores with each other and the main wellbore presents some challenges. Inherently, the production zones have different characteristics such as pressure, water content, temperature, etc. These diverse characteristics may result in undesirable production patterns. For example, a pressure difference between the lateral and the main wellbore can cause migration of debris from the lateral wellbore into the main wellbore, which can result in plugging of the main wellbore. Therefore, one of the challenges for a multi-lateral junction is to prevent migration of debris and fluids between production zones.

The fracking of a lateral wellbore is sometimes impeded by the invasion of debris into that lateral wellbore that comes from other open lateral wellbores. When debris invades a lateral wellbore, it may become difficult to seal the lateral wellbore, and therefore necessary to pull out its lateral liner, and reinsert it, which in turn can involve re-supporting the junction between the lateral and the main wellbore, and re-sealing the lateral, which can be costly.

Another technical problem that arises in multilateral completion jobs, is that it is sometimes necessary to cut liners in order to remove equipment from a lateral wellbore. When this becomes necessary, it is difficult to elegantly remove liners, and additionally, difficult to apply a cut at the right depth inside the lateral wellbore.

FIG. 1 is a schematic illustration of a section through a well showing a wellbore junction of a main wellbore and a lateral wellbore. As shown in FIG. 1, the lateral wellbore 10 extends from the main wellbore 12 at a junction. The lateral wellbore 10 is accessed through a window 14 removed from a main wellbore wall. In this example, the window 14 is an opening formed by milling through a casing 15. The lateral wellbore 10 extends beyond the window 14 at an acute angle from the main wellbore 12, as better seen in FIG. 2a. The cross section of the window 14 has an elliptical or tear-drop shape defined by a lower limit 14a and an upper limit 14b where an upper edge 16 of the lateral wellbore 10 extends away from the main wellbore 12. The elliptical shape of the window 14 forms a substantially V-shaped downhole end 14a.

FIG. 2a is a schematic illustration of a liner running tool installing a liner in a lateral wellbore, as described and illustrated in U.S. Pat. No. 9,644,459 (Themig), entitled “Wellbore Lateral Liner Placement System” and issued May 9, 2017, which is incorporated herein by reference. A short description of the system and method for placing a wellbore liner in a lateral wellbore, also described in the '459 patent, is provided in connection with FIG. 2a.

As also described in the U.S. Pat. No. 9,644,459 at FIG. 6a for example, a lateral junction support liner 120 is placed into the lateral wellbore 10 through a window (lateral opening) 114 using a running tool 118. The area around the lateral wellbore near the window is fragile and may be subject to shifting or collapse. Accordingly, a lateral junction support liner 120 deployed with (or without) cementing around it, supports the integrity of the window 114 near the junction between the main wellbore 12 and the lateral wellbore 10. A running tool 118, releasably engaging the lateral junction support liner 120, is manipulated to run the engaged lateral liner 120 into the lateral wellbore 10, and then manipulated to release its engagement of the liner 120, so that the running tool 118 can be withdrawn back to surface from the main wellbore 12. The V-shaped downhole end 114a of the window leading to the lateral wellbore is located using a key 122 biased to protrude out from the body of the running tool.

The lateral wellbore 10 can be sealed using a packer 132 for example to enable pressurization and fracking. The packer 132 and anchoring slips 134 are used to anchor the liner 120 to the lateral wellbore 10.

After the running tool 118 is withdrawn, no part of the lateral junction support liner 120 or any associated support structure for the liner 110 is protruding inside the main wellbore. Another work string can then be run in through the main wellbore 12, through the window 114, and into the lateral wellbore 10, to execute a number of operations including fracking. Another liner (not show in FIG. 2a) may extend downhole from the packer 132. The space between the lateral junction support liner 120 and the open hole of the lateral wellbore 10 that is near the window 114 can be cased and/or cemented to provide further support for the open hole region of the lateral wellbore 10 near the window 114, and thus prevent that region from degenerating and possibly caving in.

When a plurality of lateral wellbores extends from the main wellbore 12, the main wellbore 12 and lateral wellbores 10 are collectively referred to as a multilateral well. Fracking of multilateral wells presents some problems when the main wellbore 12 is left relatively unobstructed, as is the case with the system of FIG. 2a. The fracking of a lateral wellbore 10 can be impeded by the invasion of debris into that lateral wellbore that comes from the main wellbore 12 or other open lateral wellbores connected to the main wellbore 12. When debris invades the lateral wellbore 10, it may become difficult to seal it, and therefore necessary to pull out the lateral liner 120, and reinsert the liner 120, which in turn can involve re-supporting the junction near the window 114 with cement. This is both costly and time consuming.

U.S. Pat. No. 5,477,925 (Trahan et al) entitled “Method for multilateral Completion and Cementing the Junction with Lateral Wellbores” issued Dec. 26, 1995 describes another system for multilateral well cementing and completion that attempts to address this debris invasion problem. As illustrated in FIG. 4 of the '925 patent, reproduced as FIG. 2b, a liner 32 extends down the main wellbore and bends into the lateral wellbore 18 at a window 52, which results in sealing the opening into the lateral wellbore from debris invasion sourced from other lateral wellbores or the main wellbore.

In the system of FIG. 2b, however, in order to reach parts of the well below window 52, the liner 32 and some of its supporting cement must be milled open. This operation takes a long time to perform and can generate debris that causes malfunctions.

SUMMARY

Embodiments described herein provide a dual liner assembly for a multilateral fracking system that prevents or reduces significantly invasion of debris into the multilaterals without requiring repeated milling, withdrawal, reinsertion and setting of liners in each lateral wellbore.

In accordance with one aspect described in this specification, a dual liner assembly for a multilateral fracking system assembly for a multilateral fracking system, comprises: a junction support liner adapted to be installed in a lateral wellbore at a junction with a main wellbore; an inner liner with an upper portion and a lower portion, the inner liner being positioned inside the junction support liner and extending beyond the junction support liner within the main wellbore and within the lateral wellbore when the assembly is installed; and a cut and release connector adapted to join the inner liner and the junction support liner and to enable detachment of the upper portion of the inner liner from the assembly at a predefined location with respect to the junction.

Thus, the junction support liner is provided in the lateral wellbore proximate to the window with the main wellbore, and the frack liner, also referred to as the inner liner, comprises an “upper portion” (the portion of the internal liner closer to the surface) and a lower portion (the portion of the internal frack liner farther away from the surface), coupled to each other with a liner connector. The upper portion and the lower portion are also referred to as the “upper frack liner” and the “lower frack liner”, respectively.

According to another aspect described in this specification, a method of multilateral fracking is presented. The method comprises: providing a dual liner assembly comprised of junction support liner and an inner liner including an upper portion and a lower portion releasable engaged with a cut and release connector; lowering the dual liner assembly into a main wellbore and then into a lateral wellbore; installing the dual liner assembly with the junction support liner placed into the lateral wellbore at the junction with the main wellbore and the inner liner extending beyond the junction support liner within the main wellbore and in the lateral wellbore; stimulating the lateral wellbore; cutting the inner liner at a cutting position and releasing engagement between the upper and lower portions; and removing the upper portion.

In accordance with one aspect of the present disclosure, an assembly of two connected liners can be used to line both a portion of a main wellbore leading into a lateral wellbore that is to be fracked, and the lateral wellbore itself. One of the liners is a lateral junction support liner that is a precut, pre-shaped pipe that is precision located at the junction and supports the integrity of a lateral opening (i.e. window) near the junction between the main wellbore and the lateral wellbore. Another longer frack liner is placed inside the junction support liner, and additionally protrudes from the junction support liner beyond both its ends. Thus, the lateral frack liner extends more deeply into the lateral wellbore and into part of the main wellbore than the junction support liner. With part of the frack liner present in the part of the main wellbore that leads into the lateral wellbore, fracking can thus occur in the lateral wellbore without significant fluid communication occurring between it and the main wellbore or any of the other lateral wellbores in a formation.

The upper portion of the frack liner provides extra protection from the debris that may otherwise flow into the lateral wellbore being fracked. The lower portion includes seals, packers, valves and other tools necessary to frack the lateral wellbore. The upper or lower portions can also be used to run tools into the lateral wellbore for executing a variety of operations.

According to another aspect presented in this specification, the inner (frack) liner is designed to be easily and cleanly severed at a very precise location near the liner connector, and the upper portion can be withdrawn back to surface, leaving the lower portion and the junction support liner in place. This enables access to the lateral wellbore for performing additional operations and work with tool lowered from surface. Advantageously, withdrawal of the upper portion means that the upper portion does not have to be milled through in order to reach lateral wellbores further down the main wellbore.

Still further, a cut-to-release packer provided in the main wellbore to help secure the upper portion to the main wellbore is described. Furthermore, according to one embodiment, the frack liner includes a cut and release sub positioned in the lower portion in the lateral wellbore. The cut and release sub facilitate cutting the frack liner at a precise location with respect to the junction to detach the upper portion of the frack liner from the lower portion. The upper portion can then be withdrawn back to surface after detachment from the lower portion, by releasing the packer in the main wellbore.

In accordance with still another aspect, once the frack liner has been cut and separated into an upper portion and a lower portion, neat withdrawal of the upper portion from the lateral wellbore and main wellbores back to surface can be facilitated if a porous media (e.g., foam rubber or other spongy material) is pre-wrapped around the upper portion prior to lowering it into the main and lateral wellbores. The porous media is selected to inhibit the formation of a strong cement structure around the upper portion when it is deployed downhole. If left untreated, such a formation could complicate removal of the upper portion from the main and lateral wellbores, and from the junction support liner to the extent it overlaps with the upper portion, even after the upper portion is detached from the lower portion at the release sub. By wrapping the porous media around the upper portion, the porous media ends up deployed:

• • between the cement casing of the main wellbore and the upper portion when looking further uphole near the junction/window, and between the junction support liner and the upper portion when looking further downhole and farther away from the junction/window, from a radial perspective; and,
  • between the junction/window, at where cement is deployed for support of the open-hole region, and the cut release sub joining the upper and lower portions together (until fracking is completed), from an axial perspective.

Use of the porous media around the upper portion can ease withdrawal of the upper portion from the lateral wellbore support liner after it has been separated from the lower portion, without compromising the cement deployed around the lateral junction support liner (which is used to support the integrity of the lateral opening/window at the junction between the main and lateral wellbores).

Also described herein is use of locating keys for enabling deployment of the upper portion, whether or not connected to the lower portion, at a precise spot relative to the window between the main wellbore and lateral wellbore. Such a locating key is preferably provided on the upper portion, rather than on a separate running tool, the lower portion or the junction support liner.

It is to be understood that other aspects of the present invention will become readily apparent to those skilled in the art from the following detailed description, wherein various embodiments of the invention are shown and described by way of illustration. As will be realized, the invention is capable for other and different embodiments and its several details are capable of modification in various other respects, all without departing from the spirit and scope of the present invention. Accordingly, the drawings and detailed description are to be regarded as illustrative in nature and not as restrictive.

DETAILED DESCRIPTION

This disclosure and the various features and advantageous details thereof are explained more fully with reference to the non-limiting embodiments that are illustrated in the accompanying drawings and detailed in the following description. Descriptions of well-known starting materials, processing techniques, components and equipment are omitted so as not to unnecessarily obscure the disclosure in detail. Skilled artisans should understand, however, that the detailed description and the specific examples, while disclosing preferred embodiments, are given by way of illustration only and not by way of limitation. Various substitutions, modifications, additions or rearrangements within the scope of the underlying inventive concept(s) will become apparent to those skilled in the art after reading this disclosure. Furthermore, any dimensions provided are provided by way of example and not limitation.

Before proceeding further, it should be noted that, at least with respect to a junction liner, terms “upper”, “back”, “rear” are used to refer to a being on or closer to the surface side (upwell side) of the junction liner relative to a corresponding feature that is “lower”, “forward”, “front” features. For example, an “upper” end of a liner generally refers to the feature relatively closer to the (surface side of the junction liner) than a corresponding “lower” end. However, both or neither of the “upper” and “lower” ends may be on the “upper” half of the junction liner assembly. A feature that may be referred to as an “upper” feature relative to a “lower” feature even if the features are vertically aligned may occur, for example, in a horizontal well. Furthermore, “fracking” generally refers to a wellbore stimulation technique. One of ordinary skill in the art would understand that a number of wellbore stimulation techniques can also be used. A frack liner may be suitable for delivering stimulation fluids (e.g., acid, gelled acid, gelled water, gelled oil, CO2, nitrogen, proppant laden fluids and/or other fluids) to stimulate the wellbore—that is, to increase the flow capability of the (natural or damaged) wellbore—using a variety of techniques including, but not limited hydraulic fracturing.

FIGS. 1, 2a and 2b were described in the Background section of this specification.

FIG. 3 illustrates an embodiment of a dual liner assembly for a multilateral fracking system 100 proposed in this specification. As seen in FIG. 2a, a wellbore includes a main wellbore 10 and a lateral wellbore 12 branching off from the main wellbore 10. Only one lateral wellbore is shown in FIG. 3 for simplicity, but the system 100 may include a plurality of such lateral wellbores. Although not called out, in general the main wellbore 10 is cased and the lateral wellbore 12 is lined with a steel pipe. The lateral wellbore 12 may be accessed from the main wellbore 10 through a window 101 on FIG. 3. The junction between the lateral wellbore 12 and the main wellbore 10 needs to be supported adjacent to the window 101 and the lateral wellbore 12 needs to be sealed using a packer 132 for example to enable pressurization and fracking.

In the embodiment of FIG. 3, the multilateral fracking system 100 includes a packer 102, a frack liner 110 that can be separated into an upper portion 111 and lower portion 112 at a cutting position 150, and a junction support liner 120. The junction support liner 120 may be coupled to the frack liner 110 to form a dual liner assembly 105. According to one embodiment, the frack liner 110 can be a 4-5 inches diameter liner, whereas the junction support liner 120 can be a larger, 6-7 inches diameter precut/pre-shaped junction pipe. However, one of ordinary skill in the art would understand that other sizes of liners can be used.

Although not shown, the frack liner 110 may extend further into the lateral wellbore 12 and include a number of tools, such as packers (e.g., packer 132 and additional packers), valves (e.g., sliding sleeve valves and other valves) and other tools used in fracturing operations. In other embodiments, there may be no additional tools below packer 132. A continuous inner bore can be formed such that frack liner 110 can be used to provide stimulation fluids to stimulate the lateral wellbore.

The multilateral fracking system 100 can include installation structures positioned in the main wellbore 10 and lateral wellbore 12. According to one embodiment, the packer 102 is provided to seal the main wellbore 10 above the lateral wellbore 12 to be fracked. The packer 102 may be settable to seal against the main wellbore 10 casing to achieve pressure isolation. The packer 102 may be a swell packer or mechanically extrudable packer, and may be settable in various ways such as by hydraulic, hydrostatic or mechanical actuation.

An installation structure can also be positioned along the length of the lower frack liner 112, spaced from the end of the junction support liner 120. The installation structure in the illustrated embodiment includes an open hole packer 132 and anchoring slips 134. The open hole packer 132 is provided for sealing an annulus 130 between the frack liner 110 (more particularly the lower frack liner 112) and the lateral wellbore wall, for anchoring the frack liner to the formation, and for achieving pressure isolation of the lateral wellbore 12 below packer 132. The anchoring slips 134 are used for securing the liner in the lateral wellbore 12. The packer 132 and anchoring slips 134 act against the open hole wall of the lateral wellbore 12 or a cemented lateral wellbore. The packer 132 may be a swell packer or mechanically extrudable packer, and may be settable in various ways such as by hydraulic, hydrostatic or mechanical actuation. A swell packer may also be installed just above the cutting position 150 to further support the assembly against the formation.

As indicated above, the multilateral fracking system 100 preferably comprises a dual liner assembly 105 proximate to the window 101. In accordance with one embodiment, a portion of the junction support liner 120 forms an outer liner having an inner bore with a diameter that is greater than the outer diameter of an upper portion 111 and lower portion 112 of the frack liner 110 that passes at least in part into the junction support liner 120. The junction support liner 120 helps support the lateral wellbore 12 near the window 101, to prevent the lateral wellbore 12 from collapsing. As indicated above, cement may be deployed around the outside of the junction support liner for support of the formation around the window 101. The frack liner 110 extends downhole out of the junction support liner 120 into the lateral wellbore 12, and extends uphole out of the junction support liner into the main wellbore toward the surface, and thus protects the lateral wellbore 12 from invasion of debris that may otherwise flow into the lateral wellbore 12 during fracking.

The junction support liner 120 can have an upper end 120a that is wedge-shaped. In particular, the junction support liner's upper end 120a can have an upper edge that extends at an angle relative to its long axis such that it tapers to an upper tip (end) 120b. More particularly, in some embodiments, the upper end 120a of the liner 120 may be formed to follow the shape of the upper limit of the lateral window 101 in which it is to be positioned. The liner upper end 120a may be cut at a angle across its long axis such that it has a tapering tip 120b. The angle may correspond to the angle at which the lateral wellbore 12 branches off from the main wellbore 10. The end may also be concavely shaped from side to side to follow the curvature of the main wellbore 10. The upper end can be wedge shaped tapering toward tip 120b. The junction support liner 120 can be installed so it is positioned entirely within the limits of the lateral wellbore 12 and does not protrude into the main wellbore 10.

The multilateral fracking system 100 isolates the lateral wellbore 12 being fracked from the other lateral wellbores. As a result, each lateral wellbore 12 can be fracked without debris from the other lateral wellbores entering into the lateral that is being fracked. Such isolation results in substantial costs savings in completing the fracking step, and ultimately, in completing all the steps of the production process, for that lateral wellbore.

In accordance with one embodiment, the frack liner 110 (more particularly upper portion 111) can be used to facilitate precise positioning of the junction support liner 120. In this embodiment, the frack liner 110 includes a locating key for locating the V-shaped downhole end 120a of the window 101 leading to the lateral wellbore 12. Since the shape and form of the lower end of a lateral window formed by drilling is generally known, the key can be formed accordingly.

The key 122 may be formed to locate the window as by selection of one or more of: (i) the angle α at which it extends from the upper portion body, (ii) the side to side and base to tip cross sectional shape, and (iii) the longitudinal (top to bottom) cross sectional shape. Selection of one or more of these factors can allow the key 122 to positively land on and become releasably retained on the downhole V-shaped end 120b of the window 101. For example, the key 122 may extend from the frack liner 110 and have a downhole overhanging end, which in particular extends at an acute angle from the liner body. Alternately or in addition, the downhole end of the key may have a substantially V-shape in longitudinal section, wherein the side walls to some degree taper toward the lower end of the key.

Alternately or in addition, the key 122 may be selected to have a low friction interaction with the window. For example, it may have smooth curved sides without sharp angles so that the key 122 can travel more easily along the edges of the window such that the key 122 can move down along the window after the key catches on the edge.

The key 122 is positioned on the frack liner 110 such that when the frack liner 110 is coupled to the junction support liner 120, the key 122 is exposed above the junction support liner 120 for operation to locate the window 101. The frack liner 110 and junction support liner 120 can be coupled such that the force generated by rotation of the frack liner 110 is communicated to the junction support liner 120. As such, any rotation of the frack liner 110 with the key 122 results in similar rotation of the junction support liner 120 to ensure proper placement of the junction support liner 120 in the lateral wellbore 12.

As mentioned above, the key 122 extends out from the body of the upper portion 111, effectively increasing the diameter of the frack liner 110 at the location of the key 122 to a diameter greater than the diameter of the lateral wellbore 12 in which it is to be run. The size of key 122 is selected to obstruct further advancement of liner 110 in the lateral wellbore 12, when the key 122 arrives at the window 101. For example, as the frack liner 110 moves through the window into the lateral wellbore 12, key 122 catches on the window's edge to obstruct the tool from being advanced further through the window 101. Furthermore, the key 122 stops the liner from being rotated in a direction that moves the key 122 against the edge of the window 101.

The key 122 may protrude permanently from the body of frack liner 110 or may be biased to normally protrude from the liner body but to collapse if sufficient force is applied to overcome the biasing force. The key 122 may also be normally retracted, but releasable, when desired, to an extended position (biased or not) when it is desired that the key 122 assumes the extended position.

According to the expandable key embodiment, the key 122 is biased to protrude out from the body of frack liner 110. The key 122 can be collapsed by application of force thereto to reduce its protruded length but is biased to pop out to its fully extended length, when it is free of a constraining force. The key 122 therefore can be forced inwardly to allow the upper portion 111 to move through casing in the main wellbore 10 but will pop out when it is moved into an open area adjacent the window 101, such as when it rounds the corner from the main wellbore 10 to the lateral wellbore 12.

An expandable key may be driven by a mechanism that holds the key 122 in an inactive position, for example substantially retracted, and then releases it to assume an active position. The mechanism may operate by electrical, hydraulics, biasing and/or mechanical means and may be actuated by electrical, signaling, hydraulic pressure, sensitivity to wellbore conditions (hydrostatic pressure) or by a timer.

Preferably, the key 122 has a downhole overhanging end that extends to define an acute angle between it and the outer surface of frack liner 110. The key 122 may also have side walls that come together such that the width of the key tapers toward the lower end. The side walls at the key 122 can be generally smooth from top to bottom such that they have a low friction interaction with the wellbore wall about the window edges. The side walls from the base to outer end, extend at an angle, such as a right angle, that permits them to catch on the edges of the window 101. In one embodiment, obtuse angling between these parts is avoided as this may create a ramp-like surface permitting the key to pass through the window 101.

In the illustrated embodiment of FIG. 3, the key 122 is shown above the junction support liner 120 being also used to guide and align junction support liner 120 into position relative to the window 101. The junction support liner 120 may include a positioning notch shaped to accommodate the shape of the key 122 such that junction support liner 120 can be readily and properly positioned on the frack liner 110. The notch may be positioned on the junction support liner 120 at the portion of the junction support liner 120 which is to be positioned at the V-shaped bottom end of the window and ensures that the tapering tip 120b of the junction support liner 120 is positioned on the upper liner 110 such that tip 120b becomes positioned adjacent the upper region of the window. When the upper portion is pulled out of the wellbore after fracking, the key 122 is also removed and it does not remain in the wellbore indefinitely. Therefore, key 122 will not adversely affect the diameter of the main wellbore 10 for future operations.

U.S. Pat. No. 9,644,459 (Themig), which is hereby fully incorporated as part of this disclosure for all purposes, describes embodiments of a wellbore lateral junction support liner placement system, which applies in this application to placement of the junction support liner. Embodiments described herein may incorporate features and methods described in the above-mentioned US patent.

The detachment of the upper frack liner from the lower frack liner is next described in further detail. As indicated above, the frack liner 110 is adapted to be cut at one or more precisely located cutting points. Upper frack liner 111 can then be removed from the lateral wellbore 12, leaving junction support liner 120 and lower frack liner 112 in the lateral wellbore 12. Preferably, the frack liner 110 can be cut at a point that leaves a polished bore receptacle (PBR), threaded connection, or other connection exposed in the lateral wellbore so that a new/replacement upper frack liner (or other liner) can be reconnected to the lower frack liner 112 if needed.

In the embodiment illustrated in FIG. 3, the frack liner 110 can be cut at cutting positions 150, 152 using a cutting mechanism that can precisely cut the frack liner 110. In some embodiments, a cut and release sub 140 and the packer 102 have respective locating profiles so that a cutting tool can precisely locate cutting the positions 150, 152.

In operation, the window 101 can be created by milling through a main wellbore casing. The frack liner 110 can be run in with a liner running tool using packer 102 as a liner hanger. The frack liner 110 and junction support liner 120 can be lowered into the lateral wellbore 12 using locator key 122 to locate the downhole end of window 101. The Frack liner 110 will extend into the main wellbore to the packer 102. The packer 132 can be set to help support the lower portion of the frack liner 110 and isolate the lateral wellbore 12. A swell packer (not shown) may also be provided above the cut position 150 to further support the dual liner assembly in the lateral wellbore.

The area around frack liner 110 and annulus 130 can be cemented using methods known in the art. A plug or other mechanism can be used to prevent cementing below window 101 in the main wellbore. Furthermore, frack liner 110 can include a cementing tool 190 located proximate to upper end 120a of the junction support liner 120 for cleaning out cement above the window 101. One example of the cementing tool is a StackFRACK Cementor stage tool from Packers Plus of Calgary, Alberta, Canada, though, as one of skill in the art would appreciate, other ported tools could be used. After cementing the annulus 130, the junction support liner 120, and the packer 102 can be set.

Stimulation fluid (e.g., acid, gelled acid, gelled water, gelled oil, CO2, nitrogen and/or proppant laden fluids) may be pumped down a liner 170 into the frack liner 110 to treat the lateral wellbore 12. Treatment of the lateral wellbore 12 may occur in zones as is understood in the art. During fracking, other laterals are protected from debris from the lateral wellbore being fracked by the double liner.

After fracking is completed, cut and release tool 140 can be run into the lateral wellbore 12 to cut frack liner 110 at cutting position 150. In addition, the packer 102 may be a cut-to-release packer that can be cut at cutting position 152. Then, the upper portion 111 and packer 102 can be removed. Removing the upper portion 111 also removes the key 122 since, the key 122 is connected to the upper frack liner 111. Thus, the key 122 is used to locate and help support the junction support liner 120 initially and can be left in while fracking occurs. After fracking is done, the key 122 can be removed.

The location of the cutting position 150, at which the frack liner 110 Is separated into a lower frack liner 112 and upper frack liner 111, can be precision-tied back to the junction. This is because the junction support liner 120 has a precise location with respect to the junction as taught in U.S. Pat. No. 9,644,459 (Themig), the frack liner 110 through its connection by the connector 141 to the junction support liner has a precise location with respect to the junction support liner, and the cut point has a precise location with respect to the frack liner by providing the tool 140 with a locating feature used to locate cutting position 150 so that the cuts occur at the correct depth. The locating features on the cutting tool can locate profiles on the inner bore of frack liner 110 (e.g., the inner bore of cut and release sub 140), which itself was properly located using the locator keys 122, to precisely cut the frack liner 110 at cutting position 150. Therefore, the precise location of the cutting position 150 and the uphole end of the lower portion 112, can be tied back to a known distance from the junction. In some embodiments, the uphole packer 102 may be removed with the upper portion 111.

Removal of upper portion 111 can be facilitated by the use of a porous material (e.g., a sponge like substance) that is prewrapped around the outer surface of upper portion 111 before it is run into the main and lateral wellbores. Use of porous media can inhibit the attachment of a very strong cement structure to the frack liner 110. The porous media ends up between the upper portion 111 and lateral junction support liner (i.e., the outer liner in the lateral wellbore) and between the upper portion 111 and any cement in the main wellbore 10, and discourage cement build up between the cement casing and the frack liner that would make it difficult to withdraw the upper portion 111. The frack liner can thus be easily withdrawn without compromising the casing around the main wellbore 10, or the cement that is deployed around the lateral support liner at the junction between the main wellbore 10 and lateral wellbore 12 to support the integrity of the lateral opening (i.e., the window) at that junction.

In some embodiments, chemicals may be added to the porous material to make cement that directly contacts it dissolvable when exposed to oil, for example. This weakening treatment can be applied anywhere where it is undesirable to have cement present, hardened and attached to the frack liner.

In any event, after removing the upper portion 111, a polished bore receptacle (PBR) or other connection to the uphole end of the lower portion 112 is provided in the lateral wellbore to tie back into at a later time if necessary.

After fracking a particular lateral wellbore 12 and removing upper portion 111, a new frack liner, junction support liner and lower portion can be run in to the next lateral wellbore to be fracked.

Embodiments described herein provide several advantages. First, because the frack liner 110 and junction support liner 120 are run in together, the operator will not have to run tools past the lateral until the operator is done with all the completion procedures in the lateral. Because no subsequent trips are required for a particular completion (i.e., installation of the frack string and junction support liner only require one trip into the lateral wellbore), once the frack liner 110 and junction support liner 120 are installed, there is no chance that the operator will accidently pass the lateral as can occur when multiple trips are involved.

Second, the operator can frack one lateral wellbore at a time, without worrying about invasion of debris from other lateral wellbores. Debris cannot easily migrate into the lateral and junction support liner 120 being worked upon, due to the location of the double liner (.i. comprising the frack liner 110).

Third, even if debris moves from one lateral wellbore 12 to another, because each lateral wellbore 12 is pressure isolated by the frack liner 110 and junction support liner 120, the operator has full wellbore control, meaning that the operator can circulate in a given lateral using coil tubing, or other technology to clean out the debris because there is pressure isolation of the laterals. The operator can thus clean out one lateral wellbore at a time. Moreover, debris cannot go anywhere except into a location from which debris can easily be pumped out, (because of the pressure isolation.

The ability to maintain a clean lateral wellbore opening means that an operator can clean out sand or any other debris by running coil tubing or wireline tools back in to the lateral wellbore, operating them and then pulling them back out, in and out over and over again. Moreover, the operator can also easily mill out seats if necessary. In short, in preparation for a fracking job in a lateral wellbore, the operator can perform all sorts of tasks inside the frack liner and junction support liner, then simply clean up by applying cuts and retrieving the frack liner 110 up-hole packer 102.

Another advantage of the described embodiments is that the only debris that are likely to infiltrate a given lateral wellbore is the debris resulting from cutting the frack liner 110 and the packer at the end of the frack process for that lateral wellbore. But the major pieces of debris that would be generated from the cutting—namely the packer and upper portion 111—are designed to be pulled free back to surface and thus do not become debris. As such, the system can leave a very clean lateral wellbore.

Furthermore, since each lateral can be pressure isolated, fracking of each lateral wellbore can advantageously occur using standard completion procedures known in the art.

FIGS. 4-7 are diagrammatic representations of embodiments of a dual liner assembly 200 formed by the frack liner 110 and junction support liner 120, and the operation thereof. Thus, FIG. 4 is a diagrammatic representation of a dual liner assembly and FIG. 5 is a diagrammatic representation of another embodiment of a dual liner assembly. FIG. 6 is a diagrammatic representation of cutting a dual liner assembly and FIG. 7 is a diagrammatic representation of cutting a dual liner assembly with an upper portion 111 removed. These figures do not illustrate a dual liner assembly 200 bent to adapt to the angle presented by the lateral wellbore; however, one of ordinary skill in the art would understand that the dual liner assembly 200 would be bent to match up with the lateral wellbore, out in the field. It can be shipped out however from the factory in a straight-line shape.

As seen e.g. in FIG. 4, the dual liner assembly 200 includes an inner liner 125 comprising one or more tubulars forming frack liner 110, and an outer liner 121 comprising the junction support liner 120. As indicated above, the upper portion 111 is intended to be removed from within outer liner 121, by cutting through the frack liner 110 and pulling out of its underlapping position within the outer liner 121. As such, the inner diameter (or shape) of the junction support liner 120 is selected to be larger than the outer diameter (or shape) of the frack liner 110, at least where the wellbore junction support liner 120 and frack liner 110 overlap at the dual liner assembly, such that there is an annular space 123 between the wellbore junction support liner 120 and frack liner 110. This enables fluid pressure equalization between the portions of the main wellbore and the lateral wellbore that are proximate to the window 101.

In the embodiment of FIG. 4, assembly 200 comprises one or more tubulars forming a cut and release dual liner connector 141 having an inner bore from a first end 222a to a second end 222b. In this embodiment, the upper end 222a of the connector is coupled to the junction support liner 120, e.g. by an outer liner connection 224 (threading, or other connection interval, other connection, or welding), being formed as a part of the outer liner 121 of a dual liner assembly 200. The connector 141 may further connect to inner liner 125, e.g. by an inner liner connection 146 (threading or other connection interval or other connector, or welding), being formed on upper portion 111 as a part of inner liner 125. The inner liner 125 comprises a portion of frack liner 110 that will become upper portion 111 when cut.

In this embodiment, lower end 222b of connector 141 is further adapted for connection to a downhole tubular, such as connection to the lower portion 112 of frack liner 110, which is left in the lateral wellbore when upper portion 111 is removed, as discussed in connection with FIG. 3.

Dual liner connector 141, according to one embodiment, may include one or more PBR (Polished Bore Receptacles) tubulars, such as e.g., PBR 143, providing a first PBR 144 and a second PRB 148, of different diameters. The inner diameter of the first PBR 144 may be greater than the inner diameter of the second PBR 148. In some embodiments, the inner diameter of the second polished bore receptacle 148 matches the inner diameter of upper portion 111. As will be appreciated, a polished bore may be used to provide a sealing surface against which external annular seals on a tubular can be seated. Alternately or in addition, the outer liner 121 or other portion of dual liner assembly intended to be left in the lateral wellbore 12 may include a connection structure such as a threaded or interlocking interval that is exposed when upper portion 111 is removed.

Further, as illustrated, the inner diameter of connector 141 may include a locating profile 149 provided to facilitate appropriate positioning of any cut along the frack liner 110. Locating profile 149 may be formed along or below the bottom end of inner liner 125 such that a positioning portion of a cutting device may land in the profile with a cutting mechanism spaced a set distance from the positioning portion. Profile 149 may be useful for tool locating and may for example include one or more glands, such as annular indentations having a larger inner diameter into which a dog or resilient member on a tool can drop and become secured. In one embodiment, as shown, the profile can be positioned below a location to be cut, generally indicated by reference numeral 150. For example, the profile 149 can be located in the axial bore of cut and release sub 140 below the connection point with the inner liner 125. In one embodiment, the cutting position 150 occurs between the first polished bore receptacle 144 and the second polished bore receptacle 148 at point where annular space 123 exists between the inner liner 125 and the outer liner 121.

The cutting mechanism is preferably selected such that cuts can be precisely located. In accordance with one embodiment, the cutting mechanism is a mechanical cutting mechanism that can cut inner liner 125 at a precise location. Such cutter mechanisms may cut through the frack liner 110 so that the upper portion 111 can be removed. During such cutting, the outer tubular may be abraded, but care may be taken to select a cutting procedure that does not cut the outer liner 121 through. The cutting tool, in some embodiments, can be run on wireline. The cutting tool can be used to make cuts at locations 150, 152 (see FIG. 3) so that the upper liner packer 102 and the upper portion 111 can be pulled out. In other embodiments, the cutting mechanism may be for example, a mechanical cutting mechanism.

As indicated above, the dual liner connector 141 includes an outer liner connection 224 in the form of outer threads or another connection mechanism to connect to the junction support liner 120. It can be noted that in another embodiment, the upper portion of the connector 141 may form at least a portion of the junction support liner 120. Put another way, the connector 141 may be integrated with the junction support liner 120. Other connection options include, but are not limited to, various threaded connections and welding the parts together. Liner connector 141 and junction support liner 120 form the outer liner 121 that may be concentrically arranged about the portion of frack liner 110 that forms the inner liner 125. The outer liner 121 overlaps by at least a length L frack liner 110. The overlapping length L can be varied as desired. The cutting position 150 is preferably located in length L.

As indicated above, connector 141 include an inner liner connection 146 in the form of inner threads or other inner connection mechanism to connect to the lower portion 112 of the frack liner 110 which forms inner liner 125. The frack liner 110 may connect in various ways, such as by threading the tubulars together, using, for example, latch threads or using welding. The lower portion of connector 141 can couple to other tubulars. Other connection options include, but are not limited to, threaded connections, and, welding the parts.

Liner connector 141 provides a strong connection such that frack liner 110 can be used as a running tool to push and pull junction support liner 120 during installation.

According to one embodiment, a connector 141 with a triple threaded connection may be used, with threads for connecting to the junction support liner 120, the lower portion tubular 112 of the frack liner 110, and the cut and release sub 140 (seen FIG. 3). A triple threaded connector 141 can provide full mechanical strength. As seen in FIG. 4, PBR tubular 143 comprising a first PBR 144 and a second PBR 148 can provide a triple thread connector if a thread for the cut and release tool 140 is further provided on this tubular. In yet other embodiments, the PBRs may comprise other tubulars. Furthermore, connector 141 may not include a PBR.

With reference to FIG. 5, cement 204 may be introduced in the annulus 130 to help better connect junction support liner 120 with the formation, and seal the annulus of the lateral wellbore from the main wellbore. However, excess cement may impede the ability to pull the upper portion 111 of frack liner 110 free from the junction support liner 120 or connector 141. According to one embodiment, the upper portion 111 can be coated with materials that prevent cement from sticking to the metal outer surface or that reduces the structural integrity of any cement that comes into direct contact with the materials.

The withdrawal of upper portion 111 needs to happen neatly and quickly even though a lot of cement might be deployed near the junction and elsewhere to keep it in place in the main wellbore and lateral. This neat withdrawal of the upper portion 111 may be effected by the use of the release sub 140 and the use of a porous media 202 between the inner and outer liners in the lateral wellbore 12, and between the cement 204 and the liner in the main wellbore 10, to inhibit the formation of a strong cement structure that would complicate removal of the upper frack liner 111. Deployment of the porous media 202 results in weak/brittle cement formation, thus making it easier to withdraw the upper frack liner 111. In one embodiment, the porous media 202 can be any suitable porous material such as a foam rubber or other spongy material.

In some embodiments, the porous media 202 may extend over the length of the upper portion 111. In accordance with one embodiment, the porous media 202 may be a porous material with an open cell structure in which interconnected pockets within the material permit the passage of gasses or liquids between the cells. The porous media 202, in some embodiments, may be an open cell or combined open cell and closed cell foam or sponge. The porous media 202 can be selected such that, while some cement solids may penetrate the porous media, there will be insufficient particulates for the cement to set up as a cement solid in the porous media, or so that any cement that does form in the media will be weak or brittle thus making it easy to withdraw the upper portion 111 from the outer liner 121.

In one implementation, the porous media 222 can be formed of a stretchable neoprene fabric with nylon fabric covering and perforations. By way of example, but not limitation, the neoprene fabric may be neoprene fabric available from Marco International of Irvine, Calif. with an Airprene finish (see Appendix D). The generally soft nature of neoprene in combination with the perforations is believed to prevent undue pressure distribution that would cause increased fracturing pressures. The neoprene jacket may be adhered to the outer surface of upper portion 111 using a suitable adhesive, including, but not limited to 3M-SCOTCH WELD-Weather Stripping and Gasket Adhesive 1300 from 3M Corporation of St. Paul, Minn. or Permatex Super Weatherstrip Adhesive #81850 by Permatex of Hartford, Conn.

In addition, or in the alternative, the entire outer diameter (OD) of the upper portion of the frack liner 110 can be coated with a Teflon coating to also help prevent cement from sticking to it. This could be done, in some embodiments, as a substitute, in addition or as a backup to the porous media 202 wrapping on the running tool.

Each lateral wellbore frack job can involve, after fracking is complete, a precision cut with the cutting tool at the connector 141 and another precision cut at the up-hole packer 102 (which also includes a locating profile for the cutter to match up with), prior to removal of the upper portion 111 and the up-hole packer 102.

With reference to FIG. 6, a diagrammatic representation illustrating cutting of the frack liner 110 is provided. In the illustrated embodiment, a cutting tool 250 having locating keys 255 and cutters 260 is illustrated. The locating keys 255 are adapted to locate locating profiles 149 of cut and release sub 140 and are spaced from the cutters 260 such that the cutters 260 will cut at the cutting position 150 when the profiles 149 are located. Thus, the cut can be precisely located. It can be noted that the packer 102 of FIG. 3 can incorporate similar profiles so that the frack liner 110 can be precisely cut at cutting position 152.

According to one embodiment, the locator keys 255 on the cutting tool 250 allow the operator to figure out the depth to which to run in the cutting tool 250 before applying a cut. The locator keys 255 may be spring loaded and match the locating profile 149, and can engage the profile 149 upon application of a substantial force (e.g., a 90001b force) that overcomes the spring loading. The spring-loaded cutter can be used over and over for different cut and release subs in different lateral wellbores, by each time positioning the cutter exactly where it needs to be when a cut is applied. According to one embodiment, the cut will always occur just above the connection to the inner liner 125.

FIG. 7 is a diagrammatic representation of the dual liner assembly 200 with the upper portion 111 removed. It can be noted that removing the upper portion 111 can reveal first PBR 144. As such, either first PBR 144 or second PBR 148 can be used to connect a new/replacement upper portion when needed. Moreover, since first PBR 144 and second PBR 148 have different inner diameters, this means that different sizes of upper liners 111 can be connected. Furthermore, in some embodiments, the connector 141 may include threads or interlocking mechanisms such that cutting and removing the upper portion 111 from the dual liner assembly can leave these threads exposed. Therefore, a new upper frack string can be threaded back into the dual liner connector 141. In addition or in the alternative, the dual liner connector 141 may include seals that are left in place when the upper portion 111 is removed. The threaded connection (or other connection interval) of the one or more PBRs and/or remaining seals can provide a mechanism for connecting a new upper frack string without exotic sealing devices.

The dual liner connector 141, locating profile 149 and the use of standard size liners all work together to do away with the need for complicated seals, in an economical and simple manner. In one embodiment, an operator can insert the lower end of a new replacement upper portion into the PBR 144 or 148 that was previously left in the lateral wellbore, to seal back into the lower portion.

U.S. Pat. No. 7,992,645, which is incorporated as part of this disclosure for all purposes, describes one embodiment of a cut and release sub using a two-sided threaded connection. As mentioned before, other options are possible such as by forming the parts, welding the parts, etc. According to this embodiment, junction support liner 120 is coupled to a connection 144 to act as an outer tubular and the lower end of upper portion 111 may be coupled to a connection 148 to act as an inner tubular. Other cut and release arrangements may also be used.

With brief reference to FIG. 8, one embodiment of a dual liner assembly is illustrated, showing a triple threaded connector similar to the two-sided threaded connector of the incorporated U.S. Pat. No. 7,992,645. In this embodiment, a connection is provided for the upper portion 111, another connection is provided for the junction support liner and a third connection provides the locating profile for the cut and release tool. In one embodiment, the outer tubular, the junction support liner 120, and the inner tubular is a portion of the frack liner 110, namely the lower portion 112. A third tubular may provide locating profile 149. Furthermore, as illustrated, the outer tubular may include threads or other connection mechanism such as liner connection 141.

Furthermore, in some embodiments, the junction support liner 120 can be wrapped in a swell material for both an open hole application (e.g., TAML Level 3) or a cemented application (TAML Level 4). One embodiment of using a swell packer in conjunction with a junction support is described in U.S. Provisional Patent Application No. 62/237,0162, entitled “Swellable Wellbore Junction Liner for Multilateral Junctions”, filed Aug. 2, 2016, attached hereto as Appendix E, which is incorporated as part of this disclosure for all purposes.

Although the invention has been described with respect to specific embodiments thereof, these embodiments are merely illustrative, and not restrictive of the invention. Rather, the description is intended to describe illustrative embodiments, features and functions in order to provide a person of ordinary skill in the art context to understand the invention without limiting the invention to any particularly described embodiment, feature or function. While specific embodiments of, and examples for, the invention are described herein for illustrative purposes only, various equivalent modifications are possible within the spirit and scope of the invention, as those skilled in the relevant art will recognize and appreciate. As indicated, these modifications may be made to the invention in light of the foregoing description of illustrated embodiments of the invention and are to be included within the spirit and scope of the invention. Thus, while the invention has been described herein with reference to particular embodiments thereof, a latitude of modification, various changes and substitutions are intended in the foregoing disclosures, and it will be appreciated that in some instances some features of embodiments of the invention will be employed without a corresponding use of other features without departing from the scope and spirit of the invention as set forth. Therefore, many modifications may be made to adapt a particular situation or material to the essential scope and spirit of the invention.

Reference throughout this specification to “one embodiment”, “an embodiment”, or “a specific embodiment” or similar terminology means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment and may not necessarily be present in all embodiments. Thus, respective appearances of the phrases “in one embodiment”, “in an embodiment”, or “in a specific embodiment” or similar terminology in various places throughout this specification are not necessarily referring to the same embodiment. Furthermore, the particular features, structures, or characteristics of any particular embodiment may be combined in any suitable manner with one or more other embodiments. It is to be understood that other variations and modifications of the embodiments described and illustrated herein are possible in light of the teachings herein and are to be considered as part of the spirit and scope of the invention.

In the description herein, numerous specific details are provided, such as examples of components and/or methods, to provide a thorough understanding of embodiments of the invention. One skilled in the relevant art will recognize, however, that an embodiment may be able to be practiced without one or more of the specific details, or with other apparatus, systems, assemblies, methods, components, materials, parts, and/or the like. In other instances, well-known structures, components, systems, materials, or operations are not specifically shown or described in detail to avoid obscuring aspects of embodiments of the invention. While the invention may be illustrated by using a particular embodiment, this is not and does not limit the invention to any particular embodiment and a person of ordinary skill in the art will recognize that additional embodiments are readily understandable and are a part of this invention.

As used herein, the terms “comprises,” “comprising,” “includes,” “including,” “has,” “having,” or any other variation thereof, are intended to cover a non-exclusive inclusion. For example, a process, product, article, or apparatus that comprises a list of elements is not necessarily limited only those elements but may include other elements not expressly listed or inherent to such process, product, article, or apparatus.

Furthermore, the term “or” as used herein is generally intended to mean “and/or” unless otherwise indicated. For example, a condition A or B is satisfied by any one of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present). As used herein, a term preceded by “a” or “an” (and “the” when antecedent basis is “a” or “an”) includes both singular and plural of such term, unless clearly indicated otherwise (i.e., that the reference “a” or “an” clearly indicates only the singular or only the plural). Also, as used in the description herein, the meaning of “in” includes “in” and “on” unless the context clearly dictates otherwise.

Claims

1. A dual liner assembly for a multilateral fracking system, comprising:

a junction support liner adapted to be installed in a lateral wellbore proximate to a junction with a main wellbore;

an inner liner having an upper portion and a lower portion, the inner liner adapted to be positioned inside the junction support liner so that the upper portion extends uphole beyond the junction support liner into the main wellbore, and so that the lower portion extends downhole beyond the junction support liner into the lateral wellbore; and

a cut and release connector adapted to enable detachment of the upper portion from the assembly.

2. The assembly as claimed in claim 1, wherein the cut and release connector includes one or more tubulars having a bore therethrough and one or more interlocking intervals.

3. The assembly as claimed in claim 1, wherein the cut and release connector comprises:

a first connection at the upper end of the connector for engaging an outer liner connection on the junction support liner; and

a second connection at the lower end of the connector for engaging an inner liner connection on the upper portion.

4. The assembly of claim 3, wherein the cut and release connector further comprises a third connection for engaging a cutting tool operated to cut the inner liner into the upper portion and the lower portion.

5. The assembly of claim 1, wherein the cut and release connector comprises a locating profile for engaging a cutting tool to cut the inner liner at a cutting position above the cut and release connector.

6. The assembly of claim 1, wherein the cut and release connector comprises an outer liner receptacle in the form of inner threads to enable connection of a further inner liner once the upper portion of the inner liner has been removed.

7. The assembly of claim 1, wherein the cut and release connector comprises an inner liner receptacle in the form of outer threads to enable connection of a further inner liner once the upper portion of the inner liner has been removed.

8. The assembly off claim 1, wherein the cut and release connector comprises

an outer liner receptacle in the form of inner threads to enable connection of a further inner liner once the upper portion of the inner liner has been removed; and

an inner liner receptacle in the form of outer threads to enable connection of a further inner liner once the upper portion of the inner liner has been removed.

9. The assembly of claim 8, wherein the outer liner receptacle and the inner liner receptacle are each is polished bore receptacles (PBR).

10. The assembly of claim 1, wherein the inner liner comprises a window locating key biased to protrude from the outer surface of the inner liner to locate and engage a window formed the at the junction between the main wellbore and the lateral wellbore.

11. The assembly of claim 10, wherein the inner liner is coupled with the junction support liner, the locating key causing the assembly to position the upper end of the window support liner over the window.

12. The assembly of claim 10, wherein the window locating key is positioned on the upper portion of the inner liner be removed with the upper portion.

13. The assembly of claim 1, further comprising a porous material wrapped on the outer surface of the upper portion, the porous material selected to inhibit formation of cement solids.

14. The assembly of claim 1, further comprising an uphole isolation packer in the main wellbore, coupled to the upper portion.

15. The assembly of claim 14, wherein the upper portion comprises a further locating profile for engaging a cutting tool to cut the inner liner at a second cutting position downhole end of the isolation packer.

16. A method of multilateral fracking comprising:

providing a dual liner assembly comprised of a junction support liner, and an inner liner including an upper portion and a lower portion that are releasably engaged with each other by a cut and release connector;

lowering the dual liner assembly into a main wellbore and then into a lateral wellbore;

hanging the dual liner assembly from an uphole packer, with the junction support liner placed into the lateral wellbore at the junction with the main wellbore, and the inner liner extending downhole beyond the junction support liner within the main wellbore, and uphole beyond the junction support liner in the lateral wellbore until it reaches the uphole packer;

stimulating the lateral wellbore;

cutting the inner liner at the cut and release connector so as to release the engagement between the upper and lower portions; and

removing the upper portion.

17. The method of claim 16, wherein lowering the dual liner assembly comprises joining the inner liner coupled to the junction support liner using the connector.

18. The method of claim 16, wherein cutting the inner liner comprises:

running-in a cutting tool in the inner liner;

engaging the cutting tool with a locating profile provided in the connector;

cutting the inner liner into the lower portion and upper portions; and

releasing the upper portion from engagement with the lower portion and the junction support liner.

19. The method of claim 16, further comprising connecting a further upper portion to the assembly using a polished bore receptacle (PBR) provided on the inner surface of the junction support liner, the PBR becoming accessible by removal of to the upper portion.

20. The method of claim 16, further comprising connecting a further upper portion to the assembly using a polished bore receptacle (PBR) provided on the outer surface of the second portion, the PBR becoming accessible by removal of to the upper portion.

21. The method of claim 16, further comprising, prior to stimulating,

sealing the uphole isolation packer in the main wellbore above the window to the lateral wellbore; and

sealing a downhole packer in the lateral wellbore, wherein the uphole packer is removed with the upper portion.