RISERLESS COMPLETIONS

Abstract

A downhole barrier system comprising: a wellbore; an upper packer; upper barrier valve; a pressure sensor; a ported sub; a lower packer; a lower pack flow port sliding sleeve; and a lower barrier valve.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 61/888,597, filed Oct. 9, 2013, which is incorporated herein by reference.

BACKGROUND

The present disclosure relates generally to methods of suspending, completing, or working over a well. More specifically, in certain embodiments the present disclosure relates to methods of suspending, completing, or working over a subsea well without the use of a marine riser and blow out preventer system.

In order to provide adequate well control and to satisfy the statutory safety requirements of many jurisdictions around the world, most operating companies adopt the principle of ensuring that at least two independently verified barriers are in place at all times during the construction or suspension of wells. Conventional methods of suspending the well may involve the use of a Mobile Offshore Drilling Unit (MODU) to install completions through a marine riser and subsea blowout preventer (BOP) conduit. Typically these conventional methods require an enclosed conduit between the wellhead and the deployment unit to maintain primary well control and monitor fluid levels in the wellbore. Using these methods may require the MODU on-site throughout the completion installation period when it could be better utilized drilling wells or performing other operations.

Other methods of suspending a well are discussed in U.S. Pat. No. 7,438,135, the entirety of which is hereby incorporated by reference. Briefly, U.S. Pat. No. 7,438,135 describes method of suspending a well that do not require the use of a BOP stack to supplement well control. Disadvantages of such method are that the barrier systems described therein may not be suitable for use in open water environments. In addition, the methods described therein include intensive high risk wireline operations to install and verify the barriers with no means to isolate the wellbore at the mudline in the event of downhole failure.

It is desirable to develop a method of suspending, completing, or working over a well that is suitable for open water installation and does not require the use of a marine riser and a blowout preventer system.

SUMMARY

The present disclosure relates generally to methods of suspending, completing, or working over a well. More specifically, in certain embodiments the present disclosure relates to methods of suspending, completing, or working over a subsea well without the use of a marine riser and blow out preventer system

In one embodiment, the present disclosure provides downhole bather system comprising: a wellbore; an upper packer; a lower packer; an upper barrier valve; a lower barrier valve; a pressure sensor; a ported sub; and a lower pack flow port sliding sleeve.

In another embodiment, the present disclosure provides an isolated wellbore system comprising: a well bore; a downhole bather; a suspension plug; and a subsea isolation device.

In another embodiment, the present disclosure provides a method comprising: providing a well system comprising a well bore and blowout preventer; placing a downhole barrier within the wellbore, installing a suspension plug at a top of the well bore; removing the blowout preventer, installing an isolation device at the top of the wellbore; removing the suspension plug, installing an upper completion into the wellbore, recovering the subsea isolation device; installing a Christmas tree at the top of the wellbore, recovering the suspension plug, and installing the Christmas tree cap on the Christmas tree.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete and thorough understanding of the present embodiments and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings.

FIG. 1 is an illustration of a downhole barrier system in accordance with certain embodiments of the present disclosure.

FIG. 2 is an illustration of an isolated wellbore system in accordance with certain embodiments of the present disclosure.

FIGS. 3A-3L are illustrations of a method in accordance with certain embodiments of the present disclosure.

The features and advantages of the present disclosure will be readily apparent to those skilled in the art. While numerous changes may be made by those skilled in the art, such changes are within the spirit of the disclosure.

DETAILED DESCRIPTION

The description that follows includes exemplary apparatuses, methods, techniques, and/or instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details.

The present disclosure relates generally to methods of suspending, completing, or working over a well. More specifically, in certain embodiments the present disclosure relates to methods of suspending, completing, or working over a well without the use of a marine riser and blow out preventer system.

In certain embodiments, the present disclosure describes methods and systems that enable upper completions to be installed without requiring the use of a drilling BOP and/or a marine riser. In certain embodiments, the methods and systems described herein are capable of maintaining a pressure control envelop and satisfying the dual barrier requirements throughout the suspension, work over, or completion of the well. In certain embodiments, the present disclosure allows for a riser-less upper completion installation to be conducted under the protection of dual barriers with capability to isolate the well should the barrier status become degraded. In certain embodiments, the installation of the well barriers can be safely and efficiently executed during the construction lower completion without additional well intervention. In certain embodiments, the present disclosure offers the ability to monitor the integrity of the bathers real time throughout any temporary well suspension and completion installation phases.

In certain embodiments, the present disclosure provides a downhole barrier system comprising a well bore and a downhole bather. Such a system is illustrated by FIG. 1. Referring now to FIG. 1, FIG. 1 illustrates a downhole bather system 100 comprising a wellbore 110 and a downhole bather 120. In certain embodiments, downhole barrier system 100 may be a “single trip primary downhole barrier.” As used herein, the term single trip primary downhole refers to a bather that may be deployed and verified by a single trip.

In certain embodiments, wellbore 110 may be a wellbore penetrating any type of subterranean formation. In certain embodiments, wellbore 110 may service any type of well. Examples of wells capable of being serviced by wellbore 110 include subsea wells, platform wells, and land wells. In certain embodiments, the well serviced by wellbore 110 may be an oil and/or gas production well or gas and/or water injection well. In certain embodiments, wellbore 110 may be lined with a casing 111.

In certain embodiments, downhole bather 120 may comprise upper packer 121, lower packer 122, upper barrier valve 123, lower barrier valve 124, ported sub 125, lower pack flow port sliding sleeve 126, and pressure sensor 127.

In certain embodiments, upper packer 121 may comprise any sealing device capable of isolating zones in a wellbore. Examples of suitable devices include production packers, straddle packers, gravel pack packers, and expanding metal-to-metal barrier devices. In certain embodiments, upper packer 121 may be positioned within wellbore 110 at the top of downhole barrier 120. In certain embodiments, upper packer 121 may isolate a top portion 112 of wellbore 110 from a bottom portion 113 of wellbore 110. In certain embodiments, upper packer 121 may isolate a top portion 112 of wellbore 110 from a middle portion 114 of wellbore 110.

In certain embodiments, lower packer 122 may comprise any sealing device capable of isolating zones in a wellbore. Examples of suitable devices include production packers, straddle packers, gravel pack packers, and expanding metal-to-metal barrier devices. In certain embodiments, lower packer 122 may be positioned within wellbore 110 below upper packer 121. In certain embodiments, lower packer 122 may isolate a bottom portion 113 of wellbore 110 from a top portion 112 of wellbore 110. In certain embodiments, lower packer 122 may isolate a bottom portion 113 of wellbore 110 from a middle portion 114 of wellbore 110.

In certain embodiments, upper barrier valve 123 may comprise any type of valve. Examples of suitable valve types include glass or ceramic discs and flapper or ball mechanisms. In certain embodiments, upper bather valve 123 may be remotely operated to permit the flow of fluids across upper barrier valve 123. In certain embodiments, upper barrier valve 123 may be positioned within wellbore 110 below or above upper packer 121 and above lower packer 122.

In certain embodiments, lower barrier valve 124 may comprise any type of valve. Examples of suitable valve types include glass or ceramic discs and flapper or ball mechanisms. In certain embodiments, lower bather valve 124 may be remotely operated to permit the flow of fluids across lower barrier valve 124. In certain embodiments, lower barrier valve 124 may be positioned within wellbore 110 below lower packer 122.

In certain embodiments, ported sub 125 may comprise any tubular component capable of providing pressure communication across the annular space/void created when installing downhole bather 120. In certain embodiments, ported sub 125 may permit the flow of fluids across ported sub 125. In certain embodiments, ported sub 125 may be positioned within wellbore 110 below upper barrier valve 123 and above lower barrier valve 124.

In certain embodiments, lower pack sliding sleeve 126 may comprise a mechanically actuated sleeve capable of isolating fluid circulation ports required for sand control circulation. In certain embodiments, the gravel pack sliding sleeve may be closed and become redundant at the completion of sand control circulation. In certain embodiments, lower pack sliding sleeve 126 may be positioned within wellbore 110 below lower packer 122 and above or below lower barrier valve 124.

In certain embodiments, pressure sensor 127 may comprise any type of pressure sensing device. In certain embodiments, pressure sensor 127 may be capable of sensing the pressure within in any portion of the wellbore. In certain embodiments, pressure sensor 127 may be positioned within wellbore 110 within middle portion 114 of wellbore 110.

In certain embodiments, downhole barrier system 100 may further comprise sand control / lower completion 130. In certain embodiments, sand control/lower completion 130 may comprise sand screens, tubing, production packers, gravel pack packers, isolation valves, telescoping joints, circulation mechanisms, hydraulic and electric cable feed-throughs and connects, pressure and temperature sensors, hydraulic and electric lines, clamps, or wet-mate connectors.

In certain embodiments, downhole barrier system 100 may further comprise an upper completion 140 and a production packer 150. In certain embodiments, upper completion 140 may comprise tubing, production packer, gas lift mandrels, telescoping joints, circulation mechanisms, downhole safety valve, chemical injection mandrel, pressure and temperature gauge mandrel, hydraulic and electric lines, clamps, or wet-mate connectors. In certain embodiments, lower most portion 141 of upper completion 140 may extend below upper packer 121 of downhole bather 120.

In certain embodiments, the present disclosure provides an isolated wellbore system comprising: a well bore; a downhole bather; a suspension plug; and a subsea isolation device. Such a system is illustrated in FIG. 2. Referring now to FIG. 2, FIG. 2 illustrates isolated wellbore system 200 comprising: well bore 210; downhole barrier 220; a suspension plug 230, and subsea isolation device 240.

In certain embodiments, well bore 210 may comprise any of the features discussed above with respect to well bore 110. In certain embodiments, wellbore 210 may comprise a casing 211 and a well head 212.

In certain embodiments, downhole bather 220 may comprise any combination of components that have been configured to provide a primary well pressure bather. In certain embodiment, each of these components may be integrated into conventional tools used during the well sandface construction phase, to provide a single trip bather system with in-built redundancy. In certain embodiments, each of these components may have data acquisition functionality that allows confirmation of the integrity of the barrier real-time throughout the lifecycle. In certain embodiments, downhole bather 220 may comprise any combination of features discussed above with respect to downhole bather 120. In certain embodiments, downhole bather 220 may be disposed within wellbore 210 below well head 212.

In certain embodiments, the suspension plug 230 may comprise an intelligent suspension plug. In certain embodiments, suspension plug 230 may be installed within wellbore 210 at wellhead 212. In certain embodiments, suspension plug 230 may seal wellbore 210. In certain embodiments, suspension plug 230 may facilitate the suspension of well bore 210 allowing for the removal of a drilling BOP. In certain embodiments, suspension plug 230 may utilize existing mechanical bridge plug technology. In certain embodiments, suspension plug 230 may be capable of monitoring the pressure below and above suspension plug 230 when installed. In certain embodiments suspension plug 230 may be capable of transmitting pressure data using acoustic telemetry real-time through its lifecycle. In certain embodiments, suspension plug 230 may be configured to allow through bore access with a workstring in the event of failure of the primary bather. In certain embodiments, the through bore access will be enabled via remote pressure pulse activation.

In certain embodiments, suspension plug 230 may be recovered during the installation of subsea isolation device 240, using specifically designed mechanical-hydraulic function incorporated in the subsea isolation device running tool. In certain embodiments, suspension plug 230 may be recovered on the same trip as the installation of subsea isolation device 240.

In certain embodiments, subsea well isolation device 240 may comprise a configuration of well control rams and preventers, connectors, guide funnels and circulation ports. In certain embodiments, subsea well isolation device 240 may comprise the mechanical components necessary to perform wellbore isolation in the event of downhole bather failure during the installation of an upper completion. In certain embodiments, subsea well isolation device 240 may have the ability to interface with a deepwater drilling BOP system. In certain embodiments, subsea well isolation device 240 may have the ability to perform bullhead top kill operations, provide orientation for an upper completion tubing hangers, and to pressure test completions post installation. In certain embodiments, subsea well isolation device 240 may be configured to interface with tubing head spool 241 installed on wellhead 212.

In certain embodiments, subsea well isolation device 240 may be of modular design. In certain embodiments, the modular design may allow for an upper portion 242 of subsea well isolation device 240 to be configured for well specific completion operations while a lower portion 243 of subsea well isolation device 240 provides well isolation functionality by facilitating dual shear/sealing capability to comply with the two barrier requirement. In certain embodiments, the modular design may allow for lower potion 243 of subsea well isolation device 240 to provide an interface platform with two established well barriers for well recovery using a drilling BOP and marine riser system deployed from a conventional MODU. In certain embodiments, upper portion 242 of subsea well isolation device 240 may be removed and replaced by a deepwater drilling BOP.

In certain embodiments, subsea well isolation device 240 may be equipped with data acquisition functionality to indicate well bore pressure and flow. In certain embodiments, subsea well isolation device 240 may serve the functionality of a subsea trip-tank. In certain embodiments, control systems on subsea well device 240 may be activated acoustically or with an ROV.

In certain embodiments, the present disclosure provides a method comprising: providing a well system comprising a well bore and a blowout preventer; placing a downhole barrier within the wellbore, installing a suspension plug at a top of the well bore; removing the blowout preventer, installing an isolation device at the top of the wellbore, removing the suspension plug, installing an upper completion into the wellbore, recovering the subsea isolation device, installing a Christmas tree, recovering the suspension plug, and installing the Christmas tree cap on the Christmas tree. In certain embodiments, the method may also comprise installing a tubing hanger plug in the wellbore. In certain embodiments, a lower most portion of the upper completion extends below a portion of a sand control and barrier system.

Referring now to FIG. 3, FIGS. 3A-3L illustrate the process steps of a method in accordance with certain embodiments of the present disclosure. FIG. 3A illustrates a well bore 300, casing 305, mud line 310, and blowout preventer 315. Well bore 300 may share any of the features discussed above with respect to wellbore 110 and well bore 210. In certain embodiments, casing 305 may line a portion of well bore 300. In certain embodiments, well bore 300 may be cased and cleaned after the end of a drilling phase.

A downhole bather 320 may then be installed within well bore 300 below mud line 310, as shown in FIG. 3B. In certain embodiments, downhole bather 320 may share any of the features discusses above with respect to downhole barrier 120 and downhole bather 220. In certain embodiments, the downhole barrier 320 may be installed within wellbore 300 in a single trip.

Once downhole bather 320 is installed within well bore 300, a suspension plug 325 may be installed at mud line 310, as shown in FIG. 3C. In certain embodiments, suspension plug 325 may share any of the common features discussed above with respect to suspension plug 230.

One the suspension plug 235 is installed, the blow out preventer 315 may be removed, as shown in FIG. 3D.

A subsea isolation device 330 and a tubing head spool 335 may then be installed, at the top of the wellbore 300 as shown in FIG. 3E. In certain embodiments, subsea isolation device 330 may share any of the common features discussed above with respect to subsea isolation device 240. In certain embodiments tubing head spool 335 may provide a landing point for the completion tubing hanger that has not been drilled through and is configured with a circulation path around the tubing hanger.

The suspension plug 325 may then be recovered as shown in FIG. 3F.

An upper completion 340 may then be installed as shown in FIG. 3G. In certain embodiments, a lower most portion of the upper completion may extend below a portion of downhole bather 320. In certain embodiments, upper completion 340 may comprises any of the common features discussed above with respect to upper completion 140.

The well may then be suspended with a tubing hanger plug 345 at the top of the upper completion 340 as shown in FIG. 3H. In certain embodiments, tubing hanger plug 345 may comprise wireline deployed locking and release properties, pressure equalization functionality, and pressure monitoring capability.

The subsea isolation device 330 may then be recovered as shown in FIG. 3I.

A Christmas tree 350 may then be installed as shown in FIG. 3J. In certain embodiments, Christmas tree 350 may comprise any conventional type of subsea Christmas tree. In certain embodiments a dry tree or debris cap may be installed temporarily prior to the Christmas tree 350 installation.

The tubing hanger plug 345 may then be recovered as shown in FIG. 3K.

A Christmas tree cap 355 may then be installed on Christmas tree 350 as shown in FIG. 3L.

While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible.

Plural instances may be provided for components, operations and/or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.

Claims

1. A downhole barrier system comprising:

a wellbore;

an upper packer;

upper barrier valve;

a pressure sensor;

a ported sub;

a lower packer;

a lower pack sliding sleeve; and

a lower barrier valve.

2. The downhole barrier system of claim 1, wherein the lower packer is positioned within the wellbore below the upper packer.

3. The downhole barrier system of claim 1, wherein the upper barrier valve is positioned within the wellbore above the lower packer.

4. The downhole barrier system of claim 1, wherein the ported sub is positioned within the wellbore below the upper barrier valve and above the lower barrier valve.

5. The downhole barrier system of claim 1, wherein the lower pack sliding sleeve is positioned within the wellbore below the lower packer.

6. The downhole barrier system of claim 1, wherein the pressure sensor is positioned within the wellbore below the upper packer and above the lower packer.

7. The downhole barrier system of claim 1, further comprising a lower completion.

8. The downhole barrier system of claim 1, further comprising an upper completion and a production packer.

9. The downhole barrier system of claim 8, wherein a lower most portion of the upper completion is positioned below the upper packer.

10. An isolated wellbore system comprising:

a well bore;

a downhole barrier positioned within the wellbore;

a suspension plug installed near the top of the wellbore at a well head; and

a subsea isolation device.

11. The isolated wellbore system of claim 10, wherein the downhole barrier comprises an upper packer, an upper barrier valve, a pressure sensor, a ported sub, a lower packer, a lower pack sliding sleeve, and a lower barrier valve.

12. The isolated wellbore system of claim 11, wherein the downhole barrier further comprises and upper completion and a production packer.

13. The isolated wellbore system of claim 10, wherein the downhole barrier is positioned within the well bore.

14. The isolated wellbore system of claim 10, wherein the suspension plug comprises an intelligent suspension plug.

15. The isolated wellbore system of claim 10, wherein the suspension plug is configured to allow through bore access with a workstring.

16. The isolated wellbore system of claim 10, wherein the subsea isolation device interfaces with a tubing head spool installed on the wellhead.

17. The isolated wellbore system of claim 1, wherein the subsea isolation device is capable of interfacing with a drilling BOP system.

18. A method comprising:

providing a well system comprising a well bore, a casing, and a blowout preventer;

placing a barrier within the wellbore;

installing a suspension plug at a top of the well bore;

removing the blowout preventer;

installing an isolation device at the top of the wellbore;

removing the suspension plug;

installing an upper completion;

installing a tubing hanger plug;

recovering the subsea isolation device;

installing a Christmas tree;

recovering the suspension plug; and

installing the Christmas tree cap.

19. The method of claim 17, wherein the barrier comprises an upper packer, an upper barrier valve, a pressure sensor, a ported sub, a lower packer, a lower pack sliding sleeve, and a lower barrier valve.

20. The method of claim 3, further comprises installing a tubing hanger plug.