US20070227744A1

US20070227744A1 - Apparatus and method for lubricating and injecting downhole equipment into a wellbore

Info

Publication number: US20070227744A1
Application number: US11/731,639
Authority: US
Inventors: Troy Austin Rodgers
Original assignee: Individual
Current assignee: Individual
Priority date: 2006-03-30
Filing date: 2007-03-30
Publication date: 2007-10-04
Also published as: US20100224374A1; US8397825B1

Abstract

An apparatus and method for lubricating and injecting downhole equipment into a wellbore includes a blowout preventer, a spool for enclosing the downhole equipment, a pressure isolation window, and a hydraulic cylinder. The blowout preventer is positioned above a wellhead. The spool is positioned above the blowout preventer. The pressure isolation window is positioned above the spool. The hydraulic cylinder is positioned above the pressure isolation window. The hydraulic cylinder comprises a rod connected to the downhole equipment, and the hydraulic cylinder is used to lower the downhole equipment into the wellbore.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of Provisional Patent Application Ser. No. 60/787,264, titled Hydraulic Lubricating System, filed 30 Mar. 2006.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

REFERENCE TO SEQUENCE LISTING, A TABLE, OR A COMPUTER PROGRAM LISTING COMPACT DISC APPENDIX

Not applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention
The present invention relates generally to the production of petroleum products from subterranean wells. The present invention more particularly relates to the assembly of downhole equipment before deployment into a subterranean well.
2. Description of Related Art
Coiled tubing is often used to deploy downhole equipment. Coiled tubing can be defined as any continuously-milled tubular product manufactured in lengths that require spooling onto a take-up reel. Although initially used primarily for well cleanout and acid stimulation applications, coiled tubing is now used in other applications, including well unloading, fishing, tool conveyance, setting plugs and retrieving plugs. The term “downhole tool” or “downhole assembly” refers generally to the downhole equipment that is deployed and used in a subterranean well. Electrical submersible pumps, fishing tools and monitoring devices are common examples of downhole equipment.
Coiled tubing units typically include an injector head that is suspended above the wellhead by a crane or derrick. The injector head provides the surface drive force to run and retrieve the coiled tubing from the well. The injector head is often used in conjunction with a stripper and a blowout preventer. The stripper is typically located between the injector head and the blowout preventer and provides the primary operational seal between pressurized wellbore fluids and the surface environment. The blowout preventer may include one or more rams that perform various functions, including supporting the hanging coiled tubing, sealing around the coiled tubing and shearing the coiled tubing.
One of the drawbacks of using coiled tubing in conjunction with downhole equipment is the process used to connect the downhole equipment to the coiled tubing before lowering the downhole equipment into the well. In the past, a conventional lubricator was used to load tools before running the tools into the live well. The lubricator is a long, high-pressure pipe that is fitted between the top of a wellhead and the bottom of the injector head. The tools are assembled inside the lubricator and connected to the coiled tubing. The lubricator is then pressurized to wellbore pressure and the assembled tools are deployed through the wellhead into the well.
While generally effective, the prior art method of lubricating tools into the well suffers significant drawbacks. Most significantly, the use of a lubricator raises the injector head high above the wellbore for the duration of the coiled tubing operation. This requires the use of large cranes or derricks that decrease the cost effectiveness and efficiency of the coiled tubing deployment. Many well sites are too remote or too small to support the use of large cranes or derricks. Furthermore, elevated injector heads are unstable in high winds and pose an increased risk to operators and equipment.
In light of the shortcomings of the existing art, there is a need for an improved apparatus and method for lubricating and injecting downhole equipment into a wellbore. The present invention is directed to these and other deficiencies in the prior art.

BRIEF SUMMARY OF THE INVENTION

An objective of the present invention is to provide an improved apparatus and method for lubricating and injecting downhole equipment into a wellbore.
In order to achieve the above-mentioned objective, the present invention includes an apparatus comprising a spool for enclosing the downhole equipment. The apparatus further comprises a pressure isolation window positioned above the spool. The pressure isolation window preferably includes a lower packing gland to retain the pressure in the spool and an upper packing gland to retain the pressure in a hydraulic cylinder. The apparatus further comprises a hydraulic cylinder positioned above the pressure isolation window, and a rod connected to the downhole equipment. The hydraulic cylinder lowers the downhole equipment into the wellbore.
The present invention allows downhole equipment to be substantially lowered into the wellbore, and allows the spool to be removed before a coiled tubing injector is attached to the well. Thus, the use of the present invention obviates the need for a conventional lubricator under the coiled tubing injector head. As such, the injector head can be operated much closer to the ground with smaller equipment and with reduced risk to person and property.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

FIG. 1 is a side cross-sectional elevational view of a preferred embodiment of the present invention.

FIG. 2 is a side cross-sectional elevational view of the pressure isolation window of a preferred embodiment of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The apparatus and method for lubricating and injecting downhole equipment into a wellbore is described below in accordance with the present invention and with reference to the drawings.
FIG. 1 shows a hydraulic lubricator assembly apparatus 100 constructed in accordance with a preferred embodiment of the invention. The apparatus 100 preferably includes a hydraulic cylinder 102, a pressure isolation window 104, a spool 106, and a blowout preventer 108. The blowout preventer 108 is connected to the top of a wellhead 110. In the preferred embodiment, the apparatus 100 is mounted on a truck (not shown) having a derrick or mast sufficient to suspend the apparatus 100 over the wellhead 110. It will be understood, however, that the apparatus 100 can alternatively be used in offshore applications and mounted on a boat or barge.
The blowout preventer 108 is preferably a standard blowout preventer used in coiled tubing operations and should be selected based on the particular requirements of specific applications. The blowout preventer 108 preferably includes a pair of internal rams 112. The blowout preventer may also include one or more pairs of shear rams or blind rams. The blowout preventer may also be attached to other BOPs.
The apparatus 100 is used to lower downhole equipment 138 into the wellbore. The downhole equipment 138 may be a single component, or alternatively made up of multiple components 138 a, 138 b, 138 c and 138 d that connect together to form the downhole equipment 138. It will be understood that the downhole equipment 138 may be made up of fewer components or more components than are shown in FIG. 1.
The spool 106 may be comprised of one or more spool segments 106 a, 106 b, and 106 c. The spool 106 is designed to contain the downhole equipment 138 prior to the insertion of the downhole equipment 138 into the wellbore. The number of spool segments depends on the length of the downhole equipment 138. Each spool segment 106 a, 106 b, and 106 c is preferably a 3″ diameter, high-pressure spacer spool. In a particularly preferred embodiment, the spool 106 is 30 feet in length, and the spool segments are installed in series.
The hydraulic cylinder 102 preferably includes a cylinder 114 having a bore 116, a rod 118 and pressure couplings 120. The hydraulic cylinder 102 is preferably connected to a hydraulic power pack or hydraulic pump (not shown) and, unless otherwise specified, is structurally and functionally similar to conventional hydraulic rams.
In the preferred truck-mounted embodiment, a dedicated diesel engine is used to drive the hydraulic power pack or hydraulic pump. The rod 118 is preferably constructed in modular rod segments such that additional lengths can be added or removed as needed as spool segments are added and removed, as discussed below. In a particularly preferred embodiment, the top of rod segment 118 b is configured for threaded engagement with the bottom of rod segment 118 a. Similarly, the top of rod segment 118 c is preferably configured for threaded engagement with the bottom of rod segment 118 b. It will be understood that additional, or fewer, rod segments may be used.
The apparatus 100 also includes a connector sub 136 that serves as a joint between the distal end of the rod 118 and the connected downhole equipment 138. In a presently preferred embodiment, the connector sub 136 is configured as a “pup-joint” with opposing ends capable of being secured to the downhole equipment 138 and the hydraulic rod 118. The functionality of the connector sub 136 is discussed below.
As shown in greater detail in FIG. 2, the pressure isolation window 104 includes a base 122, a top 124 and a series of support posts 126. The base 122 of the pressure isolation window 104 can be connected to the top of the first spool segment 106 a. The top 124 of the pressure isolation window 104 is preferably connected to the cylinder 114 of the hydraulic cylinder 102. In a particularly preferred embodiment, the pressure isolation window 104 is rigidly fixed to the hydraulic cylinder 102 for ease of transportation.
The pressure isolation window 104 also preferably includes a lower packing gland 127 and an upper packing gland 129. The lower packing gland 127 is configured to seal around the rod 118 to retain the pressure inside the spool 106. The base 122 of the pressure isolation window 104 is configured to be secured to the top spool segment 106 a through the use of a plurality of fastening devices (not shown). The lower packing gland 127 includes a packing gland body 128, a packing gland nut 134, V-packing 135, an upper packing gland pusher 136, and a lower packing gland pusher 137.
The packing gland body 128 is preferably retained within the base 122 and includes a ring seal 132 adapted to provide a suitable seal between the pressure isolation window 104 and the top spool segment 106 a. In a particularly preferred embodiment, the ring seal 132 is constructed from a material that exhibits some degree of elasticity. The packing gland nut 134 engages the packing gland body 128 to improve the seal about rod 118. Packing gland pushers 136 and 137 exert force on the V-packing 135 to tighten the seal around rod 118.
Similarly, the upper packing gland 129 is configured to seal around the rod 118 to retain the pressure within the hydraulic cylinder 114. Like the lower packing gland 127, the upper packing gland 129 preferably uses a packing gland body 130, a packing gland nut 134, V-packing 135, an upper packing gland pusher 136, and a lower packing gland pusher 137 to seal around rod 118. In this way, the pressure isolation window 104 isolates the pressure in the hydraulic cylinder 114 from the pressure in the spacer spools 106. The pressure isolation window 104 is preferably sized and configured to permit the introduction of a counter wheel or digital encoder (not shown) that can track the progression of the rod 118 in and out of the hydraulic cylinder 114.
In a preferred embodiment, the apparatus 100 is used to assemble and load the downhole equipment 138 before the downhole equipment 138 is connected to coiled tubing and deployed in the well. The use of the apparatus 100 obviates the need for a conventional lubricator under the coiled tubing injector head. The injector head can thereby be operated much closer to the ground with smaller equipment and with reduced risk to person and property.
In a preferred rig-up procedure, the blowout preventer 108 is bolted to the top of the wellhead 110. Next, the downhole equipment 138 is assembled and placed inside the requisite spool 106. Once the downhole equipment 138 is completely assembled, the connector sub 136 is attached to the top of the downhole equipment 138 and the bottom of the hydraulic rod 118.
In an alternate preferred embodiment, the hydraulic rod 118 is first connected to the connector sub 136, which in turn, is connected to the top component 138 a within the downhole equipment 138. The next component 138 b of the downhole equipment 138 is then connected to the top component 138 a. Once the length of the downhole equipment 138 is greater than the length of the first spool segment 106 a, the downhole equipment 138 is placed in the first spool segment 106 a, and the spool segment 106 a is secured to the base 122 of the pressure isolation window 104. In this fashion, additional spacer spool segments 106 b and 106 c are added to the top spacer spool segment 106 a as the length of the downhole equipment 138 increases. To facilitate assembly, the rod 118 can be extended and retracted to provide easier access to the downhole equipment 138.
Once the downhole equipment 138 has been completely assembled, the spacer spool 106 can be secured between the blowout preventer 108 and the pressure isolation window 104. Next, the spacer spool 106 is pressurized to wellbore pressure. In a first preferred embodiment, the spacer spool 106 is pressurized using a suitable compressed gas or fluid (e.g., methanol) stored on the truck. Alternatively, the spacer spool 106 can be pressurized with a bypass line connected directly to the wellbore.
When the pressure inside the spacer spool 106 is balanced with the wellbore pressure, the operator moves the master valve on the wellhead to full open. The hydraulic assembly 102 is then activated to push the downhole equipment 138 through the blowout preventer 108 and the wellhead 110 into the well. Once the connector sub 136 reaches the blowout preventer 108, the internal rams 112 are closed to lock the downhole equipment 138 in place. The travel of the hydraulic rod 118 required to move the connector sub 136 through the blowout preventer 108 is measured, preferably with the counter wheel or digital encoder, and recorded.
Next, the pressure in the spacer spool 106 is released and the spacer spool segments 106 a-c are disconnected from the blowout preventer 108. The rod 118 is then disconnected from the connector sub 136, and the depressurized spacer spool segments 106 a-c, pressure isolation window 104 and hydraulic assembly 102 are moved out of the way or rigged-down. At this point in the operation, the wellbore pressure is retained by the blowout preventer 108, and the downhole equipment 138 is suspended from the connector sub 136. The connector sub 136 is captured by the internal rams 112 of the blowout preventer 108 with the top portion of the connector sub 136 extending above the top of the blowout preventer 108.
Coiled tubing (not shown) is then attached to the exposed end of the connector sub 136 and to a coiled tubing injector head (not shown). Any intervening components, such as additional blowout preventers (not shown), are attached to the top of the blowout preventer 108. Once the intervening components are brought to wellbore pressure, the internal rams 112 are opened and the coiled tubing injector head deploys the downhole equipment 138 into the well. At the end of the coiled tubing operation, the coiled tubing is retracted until the connector sub 136 is properly positioned adjacent the internal rams 112 of the blowout preventer 108. The internal rams 112 are closed around the connector sub 136, and the injector head and any intervening components can be removed from the well site. The spacer spool 106, hydraulic assembly 102 and pressure isolation window 104 are then installed and pressurized so that the downhole equipment 138 can be retracted into the spacer spool 106 for disassembly.
Thus, the preferred embodiment provides for a hydraulically powered lubricator that can be advantageously used to load downhole equipment in a well in a separate operation before connecting coiled tubing and a coiled tubing injector head. The apparatus and method of the preferred embodiment provide an efficient and safe alternative to conventional lubricators used in combination with coiled tubing systems.
It is clear that the present invention is well adapted to carry out its objectives and attain the ends and advantages mentioned above as well as those inherent therein. While presently preferred embodiments of the invention have been described in varying detail for purposes of disclosure, it will be understood that numerous changes may be made which will readily suggest themselves to those skilled in the art and which are encompassed within the spirit of the invention disclosed herein and in the associated drawings. For example, the hydraulic assembly 102, pressure isolation window 104 and blowout preventer 108 can be cooperatively used for fishing operations that require substantial “push-and-pull” forces.

Claims

1. An apparatus for lubricating and injecting downhole equipment into a wellbore comprising:

a spool for enclosing the downhole equipment;

a blowout preventer positioned below the spool;

a pressure isolation window positioned above the spool, wherein the pressure isolation window comprises a lower packing gland and an upper packing gland; and

a hydraulic cylinder positioned above the pressure isolation window, wherein the hydraulic cylinder comprises a rod connected to the downhole equipment.

2. The apparatus of claim 1, wherein the blowout preventer comprises internal rams.

3. The apparatus of claim 1, wherein the spool comprises a plurality of spool segments.

4. The apparatus of claim 1, wherein the pressure isolation window further comprises a base connected to the lower packing gland, a top connected to the upper packing gland, and a support.

5. The apparatus of claim 1, wherein the lower packing gland and the upper packing gland each comprises a packing gland body, a packing gland nut that engages the packing gland body, V-packing, and a packing gland pusher.

6. The apparatus of claim 1, wherein the lower packing gland further comprises a ring seal.

7. The apparatus of claim 1, wherein the rod is connected to the downhole equipment via a connector sub.

8. The apparatus of claim 1, wherein the rod comprises modular rod segments.

9. A method for lubricating and injecting downhole equipment into a wellbore comprising the steps of:

positioning a blowout preventer above a wellhead;

positioning a spool above the blowout preventer;

assembling the downhole equipment in the spool;

positioning a pressure isolation window above the spool, wherein the pressure isolation window comprises a lower packing gland and an upper packing gland;

positioning a hydraulic cylinder above the pressure isolation window, wherein the hydraulic cylinder comprises a rod connected to the downhole equipment.

10. The method in accordance with claim 9, wherein the blowout preventer is connected to the lower end of the spool.

11. The method in accordance with claim 9, wherein the blowout preventer comprises internal rams.

12. The method in accordance with claim 9, wherein the pressure isolation window is attached to the upper end of the spool.

13. The method of claim 12, wherein the spool comprises a plurality of spool segments that are subsequently attached in order to enclose the downhole equipment as it is being assembled.

14. The method in accordance with claim 9, wherein the spool comprises a plurality of spool segments.

15. The method in accordance with claim 9, wherein the pressure isolation connector further comprises a base connected to the lower packing gland, a top connected to the upper packing gland, and a support.

16. The method in accordance with claim 9, wherein the lower packing gland and upper packing gland each comprise a packing gland body, a packing gland nut that engages the packing gland body, V-packing, and a packing gland pusher.

17. The method in accordance with claim 9 wherein the lower packing gland further comprises a ring seal.

18. The method in accordance with claim 9 wherein the rod is connected to the downhole equipment via a connector sub.

19. The method in accordance with claim 9, wherein the rod comprises modular rod segments.