SINGLE RUN SYSTEM FOR RUNNING LINER AND SUSPENSION PLUG DOWN HOLE AND METHOD OF USING SAME

Description

REFERENCE TO RELATED APPLICATION

This application claims priority of U.S. provisional patent application Ser. No. 63/685,996 filed Aug. 22, 2024, and hereby incorporates this provisional patent application by reference herein in its entirety.

FIELD

Embodiments taught herein relate to a system and method for running a liner and suspension plug down hole and in particular, a system and method directed to installing a liner with a packer within a wellbore and subsequently installing a suspension plug up hole of the liner and packer during one run-in of the wellbore.

BACKGROUND

When a wellbore is created, it is common practice to install several casings within the wellbore to control the outflow and inflow of fluids and gases from and into the formation surrounding the wellbore, as well as to strengthen the integrity of the wellbore by preventing its collapse. In general, a wellbore has three sections. A first section comprising a cemented casing, a second section comprising a liner, and a third section where the wellbore is open, with no additional structure to support its outer walls.

Conventionally, wellbores are drilled in sections and casings, also referred to as liners, are installed by being lowered through a previously installed casing of an up hole section. The first section of a wellbore may be lined with an intermediate casing, which may be used to isolate production zones, unstable well sections, or low-pressure zones. Traditionally, a liner top packer is positioned within an intermediate casing and supports a liner which extends down hole from the intermediate casing. More particularly, the liner extends from the intermediate casing into a section of the wellbore with no casing. To install the liner in the wellbore, conventional procedures involve running the liner into the wellbore and positioning the liner down hole, and at least partially inside, of a cemented casing or a previously placed liner. The liner is traditionally held in place by the liner top packer placed within the cemented casing or previously placed liner.

Liners are an essential component of the wellbore, and in particular function to maintain well integrity, prevent fluid loss, and preserve the well. To optimize the benefits of a liner, proper positioning is essential. Once the liner is set at a desirable position, a packer or liner setting tool is activated to install the liner. Thereafter, a plug is used to seal the wellbore at a pre-determined location to allow for treatment and/or production of the well.

Conventional drilling procedures require two trips down the wellbore to install the liner and the plug. On the first trip, the liner and liner top packer are run into the well using a setting tool and installed in position. The setting tool is then retrieved up hole. On the second trip, the suspension plug is run into the well to the liner top or pre-determined depth which is set and deployed to seal the wellbore. The drilling tool is again pulled back up hole. Running the drilling tool down the well multiple times requires additional time, expense, and contributes to wear and tear on the well formation and casing.

To prevent two trips downhole, new drilling procedures have been implemented to run a drilling tool downhole to install a liner and plug in one run. In these applications, the liner and liner top packer are positioned and installed. The plug is then positioned and installed within the liner, downhole of the liner top packer.

SUMMARY

The disclosure provides a single run system for use in setting a liner and a suspension plug in a wellbore and a method of using same.

In one aspect, there is provided a single run system for use in setting a liner and a suspension plug in a wellbore comprising: a running tool having a downhole end; a liner releasably connected to the running tool; a suspension plug setting tool having an up hole end and a downhole end and connected to the downhole end of the running tool via its up hole end; and a plug section connected to the downhole end of the suspension plug setting tool.

In some embodiments, the running tool comprises a setting piston, a locking collet, a ball seat shear sleeve, and tubing flow valve and a packer assembly.

In some embodiments, the packer assembly comprises an activation housing and a mandrel.

In some embodiments, the plug section comprises a suspension packer, an inflatable packer, a bridge plug or a completion packer.

In some embodiments, the plug section comprises a bull plug.

In some embodiments, the suspension plug setting tool comprises a top sub and a bottom sub, wherein the top sub and the bottom sub detach when activated. In other embodiments, the suspension plug setting tool is a hydraulic piston style setting tool which shears away from the suspension plug when activated.

In other aspects, there is provided a method of setting a liner and a suspension plug in a wellbore, the method comprising: providing a single run system comprising a running tool with a downhole end and comprising a packer assembly, a liner releasably connected to the running tool, a suspension plug setting tool having an up hole end and a downhole end and connected to the downhole end of the running tool via its up hole end, a plug section connected to the downhole end of the suspension plug setting tool; running the single run system into the wellbore; activating the running tool to set the packer assembly and install the liner in the wellbore; detaching the single run system from the liner and the packer assembly, leaving a suspension plug running tool moveable within the wellbore; pulling the suspension plug running tool up hole such that the suspension plug is positioned above the liner and the packer assembly; and activating the suspension plug running tool to set the suspension plug inside the casing.

In some embodiments, fluid is able to circulate through the single run system during the running in process.

In some embodiments, the running tool is pressure activated to set the packer assembly and liner. In other embodiments, the running tool is activated by mechanical means to set the packer assembly and liner.

In some embodiments, the suspension plug is actuated from an unset position to a set position using pressure. In other embodiments, the suspension plug is actuated from an unset position to a set position using mechanical means.

In some embodiments, the suspension setting tool has a top sub and a bottom sub and further comprises activating the suspension plug setting tool to detach the top sub from the bottom sub. In other embodiments, the suspension setting tool completely detaches from the suspension plug when activated.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a well schematic showing the different segments of a wellbore;

FIG. 2 is a perspective view of a single run system situated within a wellbore in a run in configuration;

FIG. 3 is an internal side view of an embodiment of a running tool;

FIG. 4 is a perspective view of a single run system in its run in position;

FIG. 5A is a perspective view of the single run system showing the packer assembly in its set position;

FIG. 5B is an enlarged partial cross-sectional view of the single run system showing features generally within circle “A” of FIG. 5A;

FIG. 6 is a partial cut-away side view of an embodiment of a running tool installed in a packer assembly;

FIG. 7 is a partial cut-away side view of an embodiment of a packer assembly in an unset position;

FIG. 8A is a perspective view of the single run system showing the running tool releasing from the packer assembly;

FIG. 8B is an enlarged partial cross-sectional view of the single run system showing features generally within circle “B” of FIG. 8A;

FIG. 9 is a perspective view of the single run system showing the running tool being pulled up hole from the packer assembly to position the plug;

FIG. 10A is a perspective view of the single run system showing the positioning of the single run system prior to inflating the plug;

FIG. 10B is an enlarged partial cross-sectional view of the single run system showing features generally within circle “C” of FIG. 10A;

FIG. 11 is a cross section view of the single run system showing the tubing flow valve and shear bypass opening ball seat in its open position to inflate the plug;

FIG. 12 is a perspective view of the single run system in the pressure up position to set the plug;

FIG. 13A is a perspective view of the single run system showing the running tool detaching from the set plug;

FIG. 13B is a perspective view of a wellbore showing the plug set within the intermediate casing and up hole of the liner top packer and liner assembly.

DETAILED DESCRIPTION

FIG. 1 is an image of a wellbore 10, showing a cased first section 12, a lined second section 14, and an open bore third section 16. The cased first section 12 includes a section lined with an intermediate casing 18. A liner top packer 24 is positioned within the intermediate casing 18. Once actuated, the liner top packer 24 holds the liner 22 in position within the wellbore 10. The liner 22 extends from the intermediate casing 18 into a downhole section of the wellbore 10. The liner 22 can be any type of liner, for example, a production liner or a steam injection liner.

Referring to FIG. 2, a single run system 100 is shown in its run-in orientation and is positioned at least in part within the intermediate casing 18. The use of the single run system 100 is not limited to setting a liner within the intermediate casing 18 and may be used within other sections of a wellbore 10 such as the surface casing. The single run system 100 features an up hole end 100a and down hole end 100b and comprises a running tool 102, a suspension plug setting tool 108, and a plug section 110. Positioned at the up hole end 100a is the running tool 102. The down hole end of the running tool 102 is connected to the suspension plug setting tool 108. Positioned at the down hole end 100b of the single run system 100, and connected to the suspension plug setting tool 108, is the plug section 110.

An embodiment of the running tool 102 is shown in FIG. 3. The running tool 102 may comprise a setting piston 112, a locking collet 114, ball seat shear sleeve 116, a packer assembly 104 and a tubing flow valve 106 (shown in FIG. 2). In some embodiments, the running tool 102 is a hydraulic release liner running tool, although embodiments are not limited to hydraulic release liner running tools. In other embodiments, the running tool 102 is a mechanical release liner running tool.

One embodiment of the packer assembly 104 is shown in FIGS. 6 and 7. The packer assembly 104 may comprise an activation housing 120, a packer element 20, a mandrel 122, and an attachment section 124. The attachment section 124 connects the packer assembly to a liner 22. The attachment section 124 can be a pin thread. The packer element 20 may be a liner top packer, debris seal packer or any type of packer which may secure the liner 22 in the well. In one embodiment, shown in FIG. 6 the packer assembly 104 may be positioned between the setting piston 112 and ball seat shear sleeve 116 of the running tool 102.

Situated at the down hole end of the running tool 102 is the tubing flow valve 106. Referring to FIG. 4, the tubing flow valve 106 may include vents, bypasses, and circulation ports to permit fluid circulation within and outside of the single run system 100. In one embodiment, shown in FIG. 8B, positioned at the down hole end of the tubing flow valve 106 are circulation ports 128. Situated at the up hole of the circulation ports 128 are at least one vent port 134 and a bypass 142 (shown in FIG. 10B). The tubing flow valve 106 may also include a first seat 119 for a first setting ball as shown in FIG. 5B.

In some embodiments, the suspension plug setting tool 108 includes a top sub 108a and a bottom sub 108b. The top sub 108a is connected to the down hole end of the running tool 102 and the bottom sub 108b is connected to the up hole end of the plug section 110. In other embodiments, the suspension plug setting tool 108 does not include separate top and bottom subs. The suspension plug setting tool 108 has two orientations, that is the run-in orientation and released orientation. FIG. 4 shows the suspension plug setting tool 108 in its run-in orientation, in which the top sub 108a and bottom sub 108b are connected. Referring to FIG. 13A, the suspension plug setting tool 108 is shown in its released orientation, in which the top sub 108a and bottom sub 108b are disconnected leaving the bottom sub 108b attached to the plug section 110 installed within the intermediate casing 18. In this embodiment, the top sub 108a remains connected to the running tool 102 and may be withdrawn from the well. In embodiments where the suspension plug setting tool 108 does not have separate top and bottom subs, the suspension plug setting tool 108 can completely disconnected from the suspension plug 140, leaving just the suspension plug 140 behind. Any mechanism known in the art that can connect and disconnect components in a downhole environment may be used to allow the top sub 108a and bottom sub 108b of the suspension plug setting tool 108 to disconnect. For example, a hydraulic disconnect or a mechanical disconnect may be used. When using embodiments without a top and bottom sub, the suspension plug setting tool 108 and suspension plug 140 can be disconnected using any known means, including shearing the suspension plug setting tool 108 away from the suspension plug 140.

Situated at the down hole end 100b of the single run system 100 is the plug section 110. The plug section 110 may comprise any suspension packer which may be installed in an intermediate casing 18 and withstand pressure applied down hole from drilling procedures and operations. In the one embodiment, the plug section 110 comprises an inflatable packer. In other embodiments, the plug section 110 comprises a bridge plug or a completions packer. The plug section 110 may also comprise a bull plug 138.

Referring to FIG. 4, a perspective view of the single run system 100 in the run-in position is shown. While in the run-in position/orientation, fluid is free to flow in and out of the circulation ports 128 of the tubing flow valve 106 and circulate around the unset plug section 110. Circulation while running the single run system 100 into the well allows the single run system 100 to move smoothly through the open hole and permits the liner 22 to extend to downhole into the open end section of the wellbore.

After the packer assembly 104 and the liner 22 are properly positioned in the well, the packer element 20 is actuated from a non-activated position to an activated position.

FIG. 5A shows one method for activating the packer element 20. FIG. 5B shows a partial cross-section view of the running tool 102 and tubing flow valve 106, generally within circle “A” of FIG. 5A. In one example, a first ball 118 is dropped through the running tool 102 and lands in the first seat 119. Once the first ball 118 is positioned within the first seat 119, fluid flow out of the circulation ports 128 of the tubing flow valve 106 is blocked. Consequently, pressure builds within the running tool 102, and the setting piston 112 of the running tool 102 may be pushed down hole towards the activation housing 120 of the packer assembly 104. A locking collet 114 functions to block the setting piston 112 from moving further downhole, thus increasing the pressure applied to the activation housing 120 by the setting piston 112.

When sufficient pressure is applied to the activation housing 120, the packer element 20 is actuated and forced towards the intermediate casing 18. In its activated position, the packer element 20 forms a seal between the intermediate casing 18 and the mandrel 122 of the packer assembly 104 and acts to anchor the liner 22.

While a ball drop process is shown, other known conventional methods may be used to block the flow of fluid and increase hydraulic pressure to actuate the packer element 20. Alternatively, other known means to actuate a packer element 20 may be used. For example, in some embodiments the packer element 20 can be actuated by mechanical means.

Extending from the packer assembly 104 is the liner 22. In some embodiments, the attachment section 124 of the packer assembly 104 may include a threaded end to be threaded to the liner. In some further embodiments, the packer assembly 104 may include a different attachment mechanism such as a slip-on box end, allowing the packer assembly 104 to be slid over the pin end of the liner and welded onto the liner. In some cases, the liner is referred to as a pipe. Once actuated, the packer element 20 secures the packer assembly 104 and the liner 22 in the well, as shown in FIGS. 8A and 8B.

Once the packer assembly 104 and the liner 22 are secured/anchored in the well, the packer assembly 104 and liner 22 may be released from the rest of the single run system 100, as shown in FIG. 9. The packer assembly 104 comprises a release sleeve 126 which shifts when pressure passes a defined threshold, allowing the packer assembly 104 and liner 22 to be released. Alternatively, other known methods to release the packer assembly 104 and liner 22 may be used.

In one embodiment, the increase in pressure used to release the packer assembly 104 and liner 22 also causes the release sleeve 126 to move downhole relative to the running tool 102, such that at least one vent ports 134 are no longer blocked by the running tool 102. When the at least one vent ports 134 are unobstructed, fluid is able to freely drain out of the work string as shown in FIG. 8B.

Referring to FIG. 9, once the packer assembly 104 and liner 22 are detached, the remaining elements of the running tool 102, the suspension plug setting tool 108 and the plug section 110 (referred to as the “plug system 150”) can be pulled up hole to position the plug section 110 above the set packer assembly 104. The plug section 110 is positioned in the casing, which may be the intermediate casing 18 or the surface casing. The packer assembly 104 and liner 22 remain secured in the intermediate casing while the plug system 150 is pulled up hole and the suspension plug 140 is set above the packer assembly 104.

FIG. 10A shows a perspective view of the plug system 150, where the plug section 110 is positioned up hole of the packer assembly 104, within casing. FIG. 10B shows an enlarged cross section view of the remaining elements of the running tool 102 (referred to as the plug running tool 152) generally within circle “C” of FIG. 10A. In one embodiment, a second ball 130 can be dropped through the plug running tool 152 and land in the bypass opening ball seat 132. The second ball 130 blocks the bypass 142 and the at least one vent ports 134, and thus stops fluid communication down hole. Pressure is applied to the well, which forces the closing sleeve 136 downhole.

Referring to FIG. 11, the closing sleeve 136 is forced downhole which opens the bypass 142. Fluid communication is permitted through the plug running tool 152 and towards the suspension plug 140. In some embodiments, situated at the downhole end of the suspension plug 140 is a bull plug 138 which forms a closed end to plug or seal the down hole end of the suspension plug 140.

In some embodiments the single run system 100 is pressurized to actuate the suspension plug 140 from an unset to a set position in the casing. In other embodiments, the suspension plug 140 can be actuated from an unset position to a set position in the casing using mechanical means. FIGS. 12, 13A and 13B show the suspension plug 140 in its set position. More particularly, the set position of the suspension plug 140 is within the intermediate casing 18 and up hole of the installed packer assembly 104.

Once the packer is in its set position, the suspension plug setting tool 108 may be used to release the plug running tool 152 from the suspension plug 140 as shown in FIG. 13A. In some embodiments, the suspension plug setting tool bottom sub 108b remains downhole attached to the plug section 110, may be used to remove the plug section 110 at a later stage in drilling or completion operations. The suspension plug setting tool top sub 108a may be removed with the remaining elements of single run system 100 when it is pulled up hole. In other embodiments, the suspension plug setting tool 108 completely disconnects from the suspension plug 140. The suspension plug setting tool 108 can be a hydraulic piston style setting tool which shears away from the suspension plug 140 when activated.

FIG. 13B shows the final position of the set suspension plug 140, packer assembly 104, and liner 22 installed in the well. The single run system 100 permits the suspension plug 140, packer assembly 104, and liner 22 to be installed in one run down hole. Setting the packer assembly 104 above the liner 22 prevents slippage of the liner 22 within the wellbore during pressure testing.

Although a few embodiments have been shown and described, it will be appreciated by those skilled in the art that various changes and modifications can be made to those skilled in the art that various changes and modifications can be made to these embodiments without changing or departing from their scope, intent or functionality. The terms and expressions used in the preceding specification have been used herein as terms of description and not of limitation, and there is no intention in the use of such terms and expressions of excluding equivalents of the features shown and described or portions thereof.