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1. (WO2018164896) MONO-BORE WELLBORE COMPLETION WITH A RETRIEVABLE PORTION
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MONO-BORE WELLBORE COMPLETION WITH A RETRIEVABLE

PORTION

CLAIM OF PRIORITY

[0001] This application claims priority to U.S. Patent Application No. 15/450,679 filed on March 6, 2017, the entire contents of which are hereby incorporated by reference.

FIELD OF INVENTION

[0002] This specification relates wellbore drilling and completion.

BACKGROUND

[0003] In hydrocarbon production, a wellbore is drilled into a hydrocarbon-rich geological formation. After the wellbore is drilled, a completion is installed to produce the wellbore and convert it into a production or injection well. The completion can help control the well and maintain well integrity. A completion can include a mono-bore completion. Mono-bore completions have large internal diameters in comparison to other types of completions and can be used when either injection or production rates are high.

SUMMARY

[0004] This specification describes technologies relating to wellbore completions, specifically mono-bore completions. For example, this specification describes mono-bore wellbore completion with a retrievable portion.

[0005] Certain aspects of the subject matter described here can be implemented as a wellbore completion system. A first polish bore receptacle includes a first uphole end and a second downhole end. The first downhole end of the first polish bore receptacle attaches at an uphole end of a liner disposed at a downhole end of a wellbore. The first polish bore receptacle accepts a first seal assembly. A second polish bore receptacle includes a second uphole end and a second downhole end. The second polish bore receptacle is disposed uphole of the first polish bore receptacle. The second polish bore receptacle receives a second seal assembly. A retrievable ratch latch assembly connects the second downhole end of the second polish bore receptacle

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and the first uphole end of the first polish bore receptacle. The ratch latch assembly and the second polish bore receptacle are retrievable from within the wellbore.

[0006] A liner hanger can attach to the first uphole end of the first polish bore and to a downhole end of the retrievable ratch latch assembly. The liner hanger can support the first polished bore receptacle and the liner downhole of the first polished bore receptacle. A tie back receptacle positioned on the uphole end of the liner hanger can receive the retrievable ratch latch assembly. The system of claim 3, wherein the tie back receptacle is less than 10 feet in length. The retrievable ratch latch assembly can lock into the tie back receptacle. The ratch latch assembly is can rotatably release from the tie back receptacle. The ratch latch assembly is can rotate in a clockwise direction to release from the tie back receptacle. A diameter of the liner can be less than or equal to substantially 7 inches. An uphole end of the tie back receptacle includes threads that couple the uphole end of the tie back receptacle to the ratch latch assembly. The tie back receptacle can threadedly connect to the retrievable ratch latch assembly. The first polish bore receptacle can be less than 5 feet in length. The first seal assembly comprises static seals that direct fluid flow through the system and prevent fluid flow from entering the wellbore through the first polish bore. The first seal assembly can be substantially three feet in length. A first sub-assembly that includes the first polish bore receptacle is can be installed into the wellbore in a first trip. A second subassembly that includes the second polish bore receptacle and the ratch assembly is can be installed into the wellbore in a second trip that is separate from and after the first trip.

[0007] Certain aspects of the subject matter described here can be implemented as a method, a first completion sub-assembly is installed in a first downhole trip within a wellbore. The first completion sub-assembly includes a liner located at a downhole end of the first completion sub-assembly, a first polish bore receptacle attached at an uphole end of the liner, and a liner hanger attached to an uphole end of the first polish bore receptacle. The liner hanger includes a tie back receptacle. A second completion sub-assembly is installed within the wellbore in a second downhole trip that is separate from and after the first downhole trip. The second completion sub-assembly includes a polish seal assembly positioned within the first polish bore receptacle, a retrievable ratch latch assembly positioned within the tie back receptacle, and an upper polish bore assembly located uphole of the retrievable ratch latch assembly.

[0008] Installing the second completion sub-assembly includes receiving the retrievable ratch latch assembly within the tie back receptacle and locking the retrievable ratch latch assembly to the tie back receptacle, the second completion subassembly can be retrieved, retrieving the second completion sub-assembly can include applying a clockwise rotation to the retrievable ratch latch.

[0009] Certain aspects of the subject matter described here can be implemented as a wellbore completion system. A liner can be located at a downhole end of the wellbore completion system. A lower polish bore receptacle can be attached at an uphole end of the liner. The lower polish bore includes static or floating seals, and a liner hanger attached to the uphole end of the lower polish bore. The liner hanger includes a tie back receptacle located on the uphole end of the liner hanger. The tie back receptacle includes an inner diameter with an ACME thread formed into the inner diameter, a polish seal assembly positioned within the lower polish bore receptacle, a retrievable ratch latch assembly positioned within the tie back receptacle, and an upper polish bore assembly located uphole of the retrievable ratch latch assembly. The lower polish bore receptacle can be substantially three feet in length. The tie back receptacle can be substantially four feet in length.

[0010] The details of one or more implementations of the subject matter described in this specification are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[001 1] FIG. 1A is a schematic diagram of an example wellbore completion system.

[0012] FIGS. 1B-1C are schematic diagrams of an example retrievable ratch latch assembly.

[0013] FIG. 2 is a flowchart of an example method for utilizing the example wellbore completion system.

[0014] FIGS. 3A-3C are schematic diagrams showing the installation of the example wellbore completion system.

[0015] FIGS. 4A-4C are schematic diagrams showing the removal of a top assembly of the example wellbore system.

[0016] Like reference numbers and designations in the various drawings indicate like elements.

DETAILED DESCRIPTION

[0017] In a mono-bore completion design, a production liner is run and cemented in the wellbore. At the top of the liner hanger is a polished bore receptacle (PBR) that is able to receive a seal assembly. The production tubing that is used has substantially the same inner diameter as a liner. When the completion is run, a seal assembly is run on the bottom of the production tubing and landed in the PBR. The seal assembly and the PBR provide an annular barrier for the tubing string to prevent fluids from leaking into a wellbore annulus, which is the space between an outer wall of the tubing and an inner wall of the wellbore. The PBR and the seal assembly allow for axial movement within the completion. Such axial movement can occur due to thermal expansion and contraction during well operations. PBRs have a smooth inner bore to seal against the seal assembly. The seals of the seal assembly can easily be damaged during operations. Yet, for the well to have a long term viability, the components of the completion system need to be changeable easily and quickly while minimizing such potentials for damage.

[0018] The mono-bore completion offers a solution to allow high pumping rates due to its large internal diameter compared to other completion methods. For example, the mono-bore completion can be implemented prior to hydraulic fracturing in unconventional gas wells, which can require a high injection rate due to the low permeability found in such wells. In such wells, the mono-bore completion can allow injection through the well despite the extreme high pressure and pumping rates required during the hydraulic fracturing. In another example, a production well with a high flow-rate can benefit from a mono-bore completion rate as well. The mono-bore completion is appropriate in any high well-flow application.

[0019] The challenge persists for seven-inch diameter or smaller liners. Incorporating a long (for example, a thirty foot) lower PBR for such liners can induce an excessive pressure drop and can increase an equivalent circulating density (ECD) while running the line in-hole or during cementing operations. A shorter PBR can eliminate or reduce the problematic pressure drop. In addition, the PBR section is suffer than a standard liner. The excess stiffness can cause difficulty when running the completion into a highly deviated well. A shorter PBR reduces or eliminates such a hazard. Manufacturing costs can also be reduced if shorter PBRs and seal assemblies are needed. The ECD is a pertinent parameter while running the completion in its first trip because the borehole is not cemented, so the geologic formation is exposed the drilling fluid. If the drilling fluid is at a sufficiently high pressure, then fluid can enter the geologic formation through the exposed walls of the wellbore and be lost. Such fluid losses do not often occur during cementing operations due to the high density of the cementing fluids compared with drilling fluids. The addition of the longer PBR, which increase the restriction length, also reduces potential fluid losses during cementing operations. During the second trip, the wellbore can have already been cemented and isolated, so the ECD is not as important a parameter while running the second trip. As a result, a longer (30 ft) PBR can be run on the second trip.

[0020] In some implementation described in this specification, a mono-bore well completion system includes a liner, a short lower polish bore receptacle, a polish seal assembly, a liner hanger, tubing joints, a retrievable ratch-latch assembly, and an upper polish bore assembly. The system can be installed in two trips. In the first trip, the liner, short lower polish bore receptacle, and liner hanger are installed. In the second trip, the polish seal assembly, tubing joints, retrievable ratch-latch assembly, and upper polish bore assembly are installed. The apparatus installed in the second trip can be retrieved by a right hand rotation of the pipe to release the latch assembly. The implementations of the system described here reduce the ECD while running in the hole and while cementing. Also, the design reduces the cost by reducing the length from 8-10 ft in the existing design to 4 ft in the proposed design.

[0021] FIG. 1A shows an example wellbore completion system 100. The wellbore completion system 100 can be particularly useful in completions where a diameter of the liner 102 is less than or equal to seven inches (within standard API

specifications) and can be designed to handle pressures up to 15,000 pounds per square inch (PSI). The wellbore completion system 100 includes a first polish bore receptacle 124 that is attached to a downhole end of a liner hanger 128. Details on the liner hanger 128 are described later within this disclosure. The first polished bore receptacle 124 includes an outer polished bore that receives an inner pipe with static seals. The inner pipe is able to axially move within the polished bore to compensate for thermal growth, or any other reason for axial movement. The downhole end 1 18 of the first polish bore receptacle 124 is attached at an uphole end 106 of a liner 122 that is designed to be disposed at a downhole end of a wellbore 138. The liner 122 can have fluid flow through its center either in the downhole direction, such as with injection or cementing operations, or in an uphole direction, such as with production operations. The first polish bore receptacle can be less than 5 feet in length. The reduced length reduces the pressure drop and subsequent increase in the ECD through the first polish bore receptacle 124 and reduces manufacturing costs. The first downhole polished bore receptacle 124 and liner hanger 128 are designed to be permanently installed in a wellbore 138. The permanent install is due to the fact that the liner hanger 128 is a permanent hanger and the liner 122 can be cemented. In some implementations, a non-permanent hanger or packer could be used to make the first polished bore receptacle and liner hanger 128 retrievable. For example, in non-cemented implementations.

[0022] The first polish bore receptacle 124 accepts a first seal assembly 1 14. The first seal assembly 1 14 includes static seals that direct fluid flow through the system and prevent fluid flow from entering the wellbore 138 through the first polish bore. That is, first seal assembly keeps fluid within the completion and prevents the fluid from leaking to a wellbore annulus 136 through the first polish bore receptacle 124. The first seal assembly 114 also prevents fluid from contacting the surface of the outer polished bore. This can extend the life of the first polished bore receptacle, especially during fracking operations. The static seals can include O-ring seals or any other type of static seal. The first seal assembly 114 is designed to fit within the first polish bore receptacle 124. So, the first seal assembly 114 can be, for example, approximately 3 feet in length if the first polish bore assembly is 5 feet in length. That is, there can be 3 feet of sealing area.

[0023] The wellbore completion system 100 also includes a second polish bore receptacle 134. The second polish bore receptacle 134 can be disposed uphole of the first polish bore receptacle 124. Similarly to the first polished bore receptacle 124, the second polished bore receptacle 134 includes an outer polished bore that receives an inner pipe with floating or static seals, sometime referred to as a production seal assembly. The inner pipe is able to axially move within the polished bore to compensate for thermal growth, or any other reason for axial movement. As the liner 102 uphole of the second polish bore receptacle 134 is very long, that is, it extends all the way to a wellhead at a topside facility (not shown), the second polished bore receptacle 134 is longer than the first polish bore receptacle 124 to account for a larger amount of thermal growth. The second polish bore receptacle 134 can receive a second seal assembly 104. Similar to the first seal assembly 114, the second seal assembly 104 also prevents fluid from contacting the surface of the outer polished bore. This can extend the life of the first polished bore receptacle, especially during fracking operations. Downhole of the second polished bore receptacle 134 is a retrievable ratch latch assembly 108 that connects the downhole end 132 of the second polish bore receptacle 134 and the uphole end 126 of the first polish bore receptacle 124. The ratch latch assembly 108 and the second polish bore receptacle 134 are retrievable from within the wellbore 138. By describing the retrievable, it is meant that the retrievable section can be easily removed without destroying any of the retrievable section or altering the wellbore, that is, material does not need to be removed from the wellbore to retrieve the ratch latch assembly 108 and the second polish bore receptacle 134. The retrievable nature of the ratch latch assembly 108 allows for easier component change-out during a well work-over. Without a removable system, the completion would need to be drilled out for removal adding extensive time and expense.

[0024] The example wellbore completion system 100 also includes the liner hanger 128 that is attached to the uphole end 126 of the first polish bore receptacle 124 and to a downhole end 130 of the retrievable ratch latch assembly 108. The ratch latch assembly 108 passes through the liner hanger 128 once installed. That is, the liner hanger 128 acts as a female connector while the ratch latch assembly 108 acts as a male connector extending through the liner hanger 128. The first seal assembly 1 14 is located at the downhole end of the male section. Details on the ratch latch assembly 108 are described later within this disclosure. In some implementations, the liner

hanger 128 can include a packer. The liner hanger 128 can support the first polished bore receptacle 124 and the liner 122 downhole of the first polished bore receptacle 124 within the wellbore 138. The example wellbore completion system 100 also includes a tie back receptacle 112 positioned on the uphole end 120 of the liner hanger 128. The tie back receptacle 112 can receive the retrievable ratch latch assembly 108 during installation. The tie back receptacle can be less than 10 feet in length. The tie back receptacle 112 can be 10 to 15 ft.

[0025] The retrievable ratch latch assembly 108 can lock into the tie back receptacle 112. The ratch latch assembly 108 can be designed to rotatably release from the tie back receptacle 112. For example, the ratch latch assembly 108 can be designed to release from the tie back receptacle 112 when the ratch latch assembly 108 is rotated in a clockwise direction. Details on the retrieval are explained later within this disclosure. An uphole end 116 of the tie back receptacle 112 can include threads 110, such as an ACME thread, that allow the uphole end 116 of the tie back receptacle 112 to be coupled to the ratch latch assembly 108. In some implementations, the threads 110 may need to be cut into the tie back receptacle 112, especially for liner sizes less than or equal to seven inches in diameter. That is, the tie back receptacle 112 is configured to threadedly connect to the retrievable ratch latch assembly 108. The threads 110 can be standard ACME threads, or any other threads. In some implementations, other types of latches can be used, such as a collet.

[0026] The retrievable ratch latch assembly 108 is shown in greater detail in FIGS. 1B-1C. The retrievable ratch latch assembly 108 can include some subassemblies such as, Top sub 108a and Ratch Latch Body assembly 108b. The top sub 108a can connect by its upper threads 140 to the lower end of upper PBR 132 and can connect by its lower threads 142 to the upper thread 144 of the ratch latch body assembly 108b. The ratch latch body assembly 108b also includes a main mandrel 154 with anti-rotating profiles 154, a ratch latch collet with ACME thread 103. The ratch latch body assembly 108b can be manufactured with same thread as liner hanger TBR top thread 110, and a locking ring 152. The main mandrel 154 can connect by its lower thread 158 to the upper thread of the seal assembly 112.

[0027] FIG. 2 shows a flowchart of a method 200 that can be implemented to install a mono-bore wellbore completion system, such as the wellbore completion

system 100. As shown in FIGS. 3A-3C, the example wellbore completion system 100 can be split into two sub-assemblies. A first sub-assembly 302 includes a liner 122 located at a downhole end of the first completion sub-assembly 302, a first polish bore receptacle 124 attached at an uphole end of the liner 122, and a liner hanger 128 attached to an uphole end 126 of the first polish bore receptacle 124. At 202, the first sub-assembly 302 is installed within the wellbore 138 in a first trip. A "trip" in this context is a single journey to a set downhole location within the wellbore 138. Such a journey involves building a string of pipe to lower into the wellbore, extending coiled or conveyed tubing into the wellbore, or using any way of lowering an object into a wellbore, such as a liner hanger running tool. Such a trip can also include pulling out the pipe with a liner hanger running tool after the first sub-assembly 302 is installed. Installing the second sub assembly 304 in a second trip allows the second sub assembly to be retrievable or recoverable. The recoverability of the second sub assembly 304 has several advantages. Such advantages can include the ability for the second sub assembly 304 to be refurbished and re-used saving costs, easing the difficulty of the first trip by making the equipment easier to handle and reducing surge pressures, improving well circulation conditions, reducing ECD and improving cementing results, and eliminating the need for milling during future interventions. A second sub-assembly 304 includes a first polish seal assembly 114 to be positioned within the first polish bore receptacle 124, a retrievable ratch latch assembly 108, and an upper polish bore receptacle 134 located uphole of the retrievable ratch latch assembly 108. At 204, the second sub-assembly 304 is installed into the wellbore 138 in a second trip that is separate from and after the first trip. As with the first trip, the second sub-assembly 304 is lowered into the wellbore. For the second trip, an extended string of the liner 102 may be used to lower the second sub-assembly 304 into the wellbore 138. The second sub-assembly 308 is inserted, or stabbed, in a downhole direction 306 into the first sub-assembly 302. In greater detail, the male part of the ratch latch assembly 108 extends into the tie back receptacle 112 and through the liner hanger 128. The downhole end of the ratch latch assembly 108 includes the first seal assembly 114 which rests within the first polished bore receptacle 124 after the second sub-assembly 304 is installed. The final insertion results in a continuous sealed flow-path between a topside facility and the wellbore through the well completion system 100.

[0028] Installing the second sub-assembly 304 can include two additional sub-steps. At 206, the retrievable ratch latch assembly 108 is received within the tie back receptacle 112. At 208, the retrievable ratch latch assembly 108 is locked into the tie back receptacle 112. The retrievable ratch latch assembly 108 can be locked into the tie back receptacle 112 with a counter-clockwise turn, with lack off weight, or with any other locking method.

[0029] In the event that maintenance is needed or components need to be changed out, the second completion sub-assembly 304 can be retrieved. Such a retrieval is shown in FIGS. 4A-4C. The second sub-assembly can be disconnected and retrieved by applying a clockwise rotation 402 to the retrievable ratch latch assembly 108. In some implementations, the second sub assembly 304 can need approximately 6 full right-hand turns to disengage from the ratch latch assembly 108. Once the retrievable ratch latch 108 has been released, the second sub-assembly 304 is pulled in an uphole direction 404, leaving the first sub-assembly 302 installed in the wellbore 138. Such a change-out may be needed after hydraulic fracturing operations, for example, due to damage to the first seal assembly 114.

[0030] A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. Accordingly, other implementations are within the scope of the following claims.