US20090260830A1

US20090260830A1 - Rigless well completion method

Info

Publication number: US20090260830A1
Application number: US12/420,073
Authority: US
Inventors: Henning Hansen
Original assignee: Individual
Current assignee: Ziebel AS
Priority date: 2008-04-18
Filing date: 2009-04-08
Publication date: 2009-10-22

Abstract

A method and system for completing a well below the bottom of a body of water includes assembling a completion string at a location away from a location of the wellbore, moving the assembled completion string to the location of the wellbore and inserting the assembled completion string into the wellbore.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This patent application claims priority to and the benefit of Provisional Patent Application Ser. No. 61/045,981 filed Apr. 18, 2008.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention
The invention relates generally to the field of completion of wellbore construction by insertion into a drilled well of a production pipe. More specifically the invention relates to methods and devices for completing or re-completing wellbores below the bottom of a body of water.
2. Background Art
Wellbore completion is the process of inserting one or more “strings” of pipe or conduit into a wellbore that has been drilled. The conduit may be a so-called “casing”, which is typically cemented into the wellbore after drilling is completed, or the conduit may be a “production tubing” which is inserted into a wellbore that already has a casing. The production tubing may include a number of different devices, such as flow control valves, sensors, control lines, artificial lift devices (e.g., gas lift valves) and annular sealing devices known as packers to seal the annular space between the casing and the outside of the production tubing.
When a wellbore is drilled, a lifting device known as a “drilling rig” is used. Operations performed in the wellbore from the drilling rig include moving drill pipe into and out of the wellbore, and running and cementing the casing in place. Such operations include threadedly coupling segments (“joints” or “stands”) of the particular pipe end to end, and moving the assembled pipe segments along the wellbore by using lifting equipment on the drilling rig.
Drilling rigs are known for use in drilling through formations below the bottom of a body of water. Certain types of such a drilling rigs float on the top of the water and lower pipe and devices through a “riser” that connects a wellhead proximate the sea floor to the floating drilling platform. See, for example, U.S. Pat. No. 6,415,867 issued to Deul et al. for a general description of drilling procedures from a floating drilling structure.
Once a wellbore has had casing cemented in place, because the casing maintains the mechanical integrity of the wellbore, the continued presence of a floating drilling structure such as a drilling rig is unnecessary
The cost of operating a floating drilling structure can be extremely expensive and includes functionality unnecessary for the wellbore completion process. Further, in some circumstances, drilling rigs could be more advantageously used elsewhere for such activities as drilling operations.

SUMMARY OF THE INVENTION

A method for completing a well below the bottom of a body of water according to one aspect of the invention includes assembling a completion string at a location away from a location of the wellbore. The assembled completion string is moved to the location of the wellbore. The assembled completion string is then inserted into the wellbore. Also the well completion can be removed from a well for repair or replacement, using the same method as described herein.
Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a schematic depiction of a method for completing a well or retrieving a well completion using a pre-assembled completion according to one example of the present invention.

FIG. 1A shows a schematic description of a safety and guiding assembly according to one example of the present invention.

FIG. 2 shows a schematic depiction of a method for running the completion through a wellhead and a safety and guiding assembly according to one example of the present invention.

FIG. 3 shows a schematic depiction of a safety and guiding assembly system installed on a subsea wellhead, according to one example of the present invention.

DETAILED DESCRIPTION

In a method according to the invention, a well completion “string”, such as a production tubing string formed from threadedly coupled pipe sections (i.e., “joints” or “stands”), may be preassembled at a shore base or other facility away from a wellsite. The wellsite is typically below the bottom of a body of water and would be drilled using a floating drilling structure. See, e.g., U.S. Pat. No. 6,415,867 issued to Deul et al. for a general description of drilling procedures from a floating drilling structure.
The techniques used to assemble the completion string may be similar to those used to preassemble product transportation pipeline, except that the pipe joints or stands in production tubing may be threadedly coupled rather than welded. Typically, the completion string would be assembled lying substantially horizontally, with an end being towed out into the water by a deployment vessel. Alternatively, the completion string can be assembled by a vessel where the string is suspended in the sea from such vessel. The assembled completion string can be pressure tested, function tested and inspected prior to being towed out to the wellsite. The present method of assembling and testing will remove the time required for such assembly from being performed on a drilling rig or similar floating vessel.
As an example of possible cost savings using a method according to the invention, one fiber optic splice in a completion string having fiber optic communication capabilities can typically take 6 to 8 hours of rig time, at a daily cost (2008) of up to one million US dollars. The proposed method significantly reduces this expenditure, and allows for more detailed and extended testing of the assembled completion system prior to deployment. As the string assembly is finished, a support vessel may suspend the other end of the completion string for deployment to the wellsite. The well completion string may be fully or partially filled with air or other gas to create the buoyancy required for safe transportation under the sea surface to the wellsite. In an alternative example, external floatation devices may be used in addition to air or gas filling for buoyancy, including both active and passive flotation aids such as foam modules or air cans. Using external buoyancy devices may be necessary when remotely assembling so called “sand-face” completion sections. Such sections typically contain sand screens, which being permeable, would make internal air filling of the assembled completion string impossible. The upper portions of the completion string longitudinally displaced from the screen or screens could, however, be sealed with an internal sealing device or plug, and use the internal air buoyancy methodology described above
Prior to installing an assembled completion string into the wellbore, the wellbore should be in a “safe” status by using downhole barriers such as casing plugs being installed, or by not yet being perforated (wherein explosive charges are used to penetrate the wellbore casing, cement external to the casing and some of the productive formation outside the wellbore). For pulling completion strings already disposed in wellbores out from such wellbores, using the above described methods, the wellbore should first be safely secured to prevent fluid entry into the wellbore from formations into which perforations extend, or in which screens are disposed. Securing a previously completed wellbore may be performed, for example using well known fluid pressure barriers, for example, mechanical plugs. In other examples high density fluids (“kill fluid”) may be pumped into the wellbore, or remotely operated downhole valves or similar maybe used. See, for example, U.S. Pat. No. 5,343,955 issued to Williams or U.S. Pat. No. 5,167,284 issued to Leismer for a description of typical wellbore safety valves.
The deployment vessel and support vessel may then move to the wellsite to enable installing the completion string. Referring to FIG. 1, the deployment vessel 20 may suspend a wellbore connection end 32 of a well completion string 30. Wellbore connection end 32 is end of well completion string 30 that will be connected to wellbore 10. Wellbore 10 may be disposed beneath subsurface wellhead 14, shown in the inset FIG. 1A in FIG. 1, disposed on the water bottom. Placement end 34 of completion string 30 may be disposed directly above wellhead 14, and placement end 34 lowered into the water from support vessel 50, such as by a winch or similar device. Deployment vessel 20 may move toward wellhead 14 as placement end 34 of completion string 30 is lowered. Deployment vessel 20 may use remotely operated vehicle (“ROV”) 60 of types well known in the art to deploy tools (not shown) and video camera (62) to cause completion string 30 to move through a suitable opening in the top of wellhead 14 (shown in greater detail in FIGS. 2 and 3). ROV 60 is typically connected to deployment vessel 20 through ROV umbilical 64, by which power may supplied to ROV 60 and data, typically including video, may be delivered to deployment vessel 20. ROV 60 may also deploy electrical and/or hydraulic cables to connect control equipment on the deployment vessel 20 to suitable controlled devices on the wellhead 14, such as blowout preventers (“BOPs”).
Tubulars, even large size tubulars such as, for example 7 inch diameter tubulars, can bend when long in comparison to the diameter. This bending is a natural property of the materials used to make completion string 30, and it is necessary for being able to run and install tubular into deviated wellbores, for example. This natural bending will allow an entire well completion string towed out to the wellhead location to bend in the water. What may be observed in FIG. 1 is that completion string 30 is bent from a horizontal orientation to a vertical orientation through wellhead 14 and into wellbore 10. The lowering of completion string 30 into wellbore 10 continues with deployment vessel 20 moving toward wellhead 14, while lowering completion string 30 into wellbore 10. Air can be pumped into or evacuated from within completion string 30 by deployment vessel 20 to create any positive or negative buoyancy required for placement of completion string 30 into wellbore 10. Alternatively, or additionally, external air canisters may be used to provide buoyancy. Such air canisters may be released from the completion string, for example, by using the ROV 60 or by acoustic command from the deployment vessel 20 or support vessel 50. It may be desirable for deployment vessel 20 to approach wellbore 10 from the same direction as the main ocean currents in the area of wellbore 10, as shown in FIG. 1. Such an approach may assist in the deployment of well completion string 30 by allowing the main ocean currents to push or guide well completion string 30 to its desired location.
In some examples of the present invention, support vessel 50 may assist in the deployment of well completion string 30. Support vessel 50 may perform such as operations as assisting in the placement of well completion string 30 or securing sections of well completion string 30 while other sections are being connected to wellhead 14.
FIG. 1 further depicts control umbilical 70. Control umbilical 70 and wellhead control umbilical 74 are connected through umbilical connector 72. These elements and their purpose are more fully described below.
FIG. 2 shows well completion string 30 as it is being moved through wellhead 14. At the time of assembly, well completion string 30 may be charged with air for buoyancy. As well completion string 30 is deployed into wellbore 10, the air inside well completion string 30 can be gradually released to cause well completion string 30 to move downwardly under gravity, to balance the weight of well completion string 30 and to provide added safety and deployment speed. However, well completion string 30 is at normally connected to deployment vessel 20 by wire and/or umbilical 36, where safe deployment speeds are controlled by the speed of deployment vessel 20 moving toward the location above wellhead 14 as well as by the lowering speed of well completion string 30 by deployment vessel (20)'s winch system.
The safety of the well completion string 30 deployment and retrieval of thereof with respect to possible dropping of the string 30 in the water can be addressed by having completion string filled with air as explained above, by the deployment wire or rope from the deployment vessel 20, and by providing external buoyancy tanks which can be activated by, for example, sensing water pressure and/or acceleration of the completion string 30 through water.
When well completion string 30 has been “landed” that is, fully inserted into wellbore 10 and a “tubing hanger” (not shown) is seated in wellhead 14, equipment disposed on deployment vessel 20 may be used in conjunction with control umbilical 70 shown in FIG. 1 to set packer(s), tubing hangers, and similar equipment, as well as to pressure test the wellbore system (the casing, wellhead and completion string). Thereafter, downhole barriers such as safety plugs or valves may be opened. If the well casing was not perforated prior to completion string 30 installation, such perforation can be performed when the system has been pressure tested and qualified. If a so-called horizontal wellhead is used, wellhead 14 would most often be installed on the seafloor prior to installation of well completion string 30. And if a so-called vertical wellhead is used, wellhead 14 would most often be installed after well completion string 30 is installed. Such wellhead installation can be performed using one or two vessels instead of a floating drilling structure.
One example of a safety- and guiding assembly 100 to be mounted onto the wellhead guide base or a horizontal type wellhead usable with the present method is shown in FIGS. 2 and 3. The components may be similar to those used in conventional sea floor well completions where a floating drilling structure is used.
As shown in FIGS. 2 and 3, wellhead 14 is connected to BOP 200. The construction of BOP 150 and its connection to wellhead 14 are generally understood by those of skill in the art. Mechanically connected to BOP 200 is lower guide funnel 110. Lower guide funnel 110 is adapted to guide well completion string 30 to properly mate with and pass through BOP 200 into wellhead 14. While lower guide funnel 110 is shown in FIGS. 2 and 3 to be conical, this shape is non-limiting.
Connectors 120 serve to mechanically connect BOP 200 to safety- and guiding assembly 100. Safety- and guiding assembly 100 typically consists of two primary parts, cylindrical body 130 and upper guide funnel 150. Upper guide funnel 150 is adapted to receive well completion string 30 as it is lowered from deployment vessel 20 and allow well completion string 30 to pass into cylindrical body 130. While upper guide funnel 150 is shown in FIGS. 2 and 3 to be conical, this shape is non-limiting. Cylindrical body 130 serves to guide well completion string 30 to lower guide funnel 110 as well completion string 30 is lowered from deployment vessel 20.
Safety- and guiding assembly 100 may also include one or more buoyancy tanks 140. Buoyancy tanks 140 are typically used to assist in placement of safety- and guiding assembly 100. Safety- and guiding assembly may also include dropped pipe grabber 160. Dropped pipe grabber 160 assists in the protection of BOP 200 and wellhead 14 from accidental misplacement of well completion string 30 or falling objects such as piping or tools.
Placement by deployment vessel 20 of well completion string 30 may be assisted through the use of camera 170. Camera 170 is focused on upper guide funnel 150. Camera 170 transmits data, such as video, to deployment vessel 20, typically through control umbilical 70. Such video allows the operator of deployment vessel 20 to more closely view the placement of well completion string 30 into upper guide funnel 150. Camera 170 is often mounted on movable arm 180; movable arm 180 is adapted to allow the operator of deployment vessel 20 to orient camera 170 during placement of well completion string 30.
The operation shown in FIG. 1 may be reversed to effect repairs on the tubing string of well completion string 30. In such repair operations, the tubing string may be moved to a location away from the location of wellbore 14, and at least one repair operation may be performed, for example, welding, replacement of a valve or other control, replacement of a packer, etc.
Methods according to the invention may save the cost of using a floating drilling structure for well completions and well re-completions.
While the invention has been described with respect to a limited number of examples, those skilled in the art, having benefit of this disclosure, will appreciate that other examples can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

Claims

1. A method for completing and re-completing a well below the bottom of a body of water, comprising:

assembling a well completion string at a location away from a location of the wellbore to form an assembled well completion string;

moving the assembled well completion string to the location of the wellbore; and

inserting the assembled well completion string into the wellbore.

2. The method of claim 1 wherein the assembling is performed substantially horizontally.

3. The method of claim 2 wherein the moving is performed by suspending in the water the assembled well completion string from at least one vessel.

4. The method of claim 1 wherein the assembling is performed by moving one end of the well completion string into the body of water by towing from a vessel while segments of the well completion string are coupled to the other end of the string.

5. The method of claim 1 wherein the moving comprises suspending the assembled well completion string from a vessel disposed proximate each end of the well completion string.

6. The method of claim 1 wherein a well completion string is removed from a well and then fully or partially disassembled horizontally at a location away from the wellbore

7. The method of claim 1 wherein the well completion string is a drill-string.

8. A method for wellbore intervention, comprising:

lifting a pipe string from within a wellbore wherein the wellbore is situated by winching one end of the pipe string thereof toward a first vessel on the surface of the water;

moving the vessel away from a location of the wellbore;

lifting the other end of the pipe string toward the surface of the water by winching the other end toward a second vessel on the surface of the water; and

moving the first and the second vessels away from the location of the wellbore.

9. The method of claim 8 further comprising moving the pipe string to a location away from the location of the wellbore and performing at least one repair operation on the pipe string.

10. A safety and guiding assembly comprising:

a substantially cylindrical body having a proximate end, a distal end, and an outer circumference;

an upper guide funnel, the upper guide funnel mechanically connected to the proximate end of the substantially cylindrical body and adapted to receive a well completion assembly; and

a connector, the connector mechanically connected to the distal end of the substantially cylindrical body and adapted to fasten the substantially cylindrical body to a BOP.

11. The assembly of claim 10 further comprising a buoyancy tank, the buoyancy tank secured to the outer circumference of the substantially cylindrical body.

12. The assembly of claim 10 further comprising a pipe grabber, the pipe grabber disposed on the outer circumference of the substantially cylindrical body.

13. The assembly of claim 10 further comprising a control umbilical, the control umbilical in mechanical connection with the substantially cylindrical body.

14. The assembly of claim 13 further comprising a camera, the camera in electrical connection with the control umbilical.

15. The assembly of claim 14 further comprising a movable arm, the arm in mechanical connection with the camera and in mechanical connection with the substantially cylindrical body.