US20070000670A1

US20070000670A1 - Method and apparatus for installing strings of coiled tubing

Info

Publication number: US20070000670A1
Application number: US11/394,397
Authority: US
Inventors: John Moore; James Hickey; Scott Vander Velde; Stephanie Benoit
Original assignee: Individual
Current assignee: Trican Well Service Ltd
Priority date: 2005-03-31
Filing date: 2006-03-31
Publication date: 2007-01-04
Also published as: CA2541481A1

Abstract

The present application discloses a system and method of guiding one or more strings of coiled tubing into a wellbore as the strings of coiled tubing are pulled into the wellbore by another coiled tubing string. The present application also discloses coiled tubing equipment for the insertion of the additional coiled tubing strings into the wellbore.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority from U.S. Provisional Application Ser. No. 60/666,630 filed Mar. 31, 2005.

FIELD OF THE INVENTION

The present application relates to oil and gas well installations in general, and to methods and apparatus for multiple independent coiled tubing string installation and use and in particular, for operating a hydraulic submersible pump in a low pressure gas well for the purpose of removing produced water from the wellbore to avoid wellbore liquid loading.

DESCRIPTION OF THE RELATED ART

Wells are drilled for the production of oil and natural gas. Natural gas often contains a fraction of water vapor in the gas itself at reservoir conditions, and in other cases the formation from which the gas is produced contains some free water in liquid state at reservoir conditions. In the case of water vapor, gas produced from the formation undergoes a degree of cooling as it is produced up the wellbore that causes the water vapor to condense to a liquid phase. In the case of a low pressure gas formation, there is insufficient velocity in the gas production stream to lift the condensed or “free” water out of the wellbore, and the free water collects at the bottom of the well and reduces or in some cases prevents gas flow. This is called “liquid loading”.
There are several ways to reduce or minimize wellbore liquid loading, including the insertion of smaller diameter tubulars to increase the gas velocity such that it is sufficient to lift the water, the use of chemical treatments intended to increase the surface tension of the water and allow for easier lifting, and the installation of a pump to mechanically remove the water.
Mechanical pumping methods generally include a pumping means, a drive means by which the pump is powered or operated, and a conveyance means by which the pumped water is removed from the wellbore. The pumping means may be a piston or positive displacement pump, centrifugal pump or other such conventional device. The drive means may be an electric power source transmitted from surface to the pump by electric cable, mechanical movement (reciprocating or rotational) of a tubular or rod extended from surface to the pumping means, a hydraulic fluid pressured from surface through one or more conduits, or some other conventional means.
The use of tubulars as the conveyance means is common. Tubulars are generally discreet lengths of tubing joined together by threaded and/or coupled ends, but may also include the use of continuous lengths of coiled tubing. It is common to have multiple strings of tubing, whether they be jointed tubing or continuous lengths of coiled tubing.
The running of each string off its own coiled tubing injector system may also be problematic due to the potential for each of the injector systems to operate at slightly different speeds, thereby again causing potential buckling issues while running in the wellborn.

SUMMARY OF THE INVENTION

According to one aspect of the present application, there is provided a method of installing strings of coiled tubing into a wellbore comprising the steps of providing a first string of coiled tubing, providing at least one other string of coiled tubing, joining the first string of coiled tubing to the at least one other string of coiled tubing, and inserting the first string of coiled tubing into the wellbore whereby, the at least one other string of coiled tubing is inserted into the wellbore by the first string of coiled tubing.
According to one aspect of the present application, there is provided an apparatus for installing strings of coiled tubing together into a wellbore comprising an injector for inserting a first string of coiled tubing into the wellbore, and a common connector for joining at least one other string of coiled tubing with the first string of coiled tubing and whereby, insertion of the first string of coiled tubing into a wellbore causes insertion of the at least second string of coiled tubing into the wellborn.
According to one aspect of the present application, there is provided an apparatus for inserting at three coiled tubing strings into a wellbore, the apparatus comprising an injector for inserting a master coiled tubing string into a wellbore, and a connector for affixing a master coiled tubing string to two slave coiled tubing strings whereby insertion of the master coiled tubing string into a wellbore causes the slave coiled tubing strings to be inserted together with the master coiled tubing string.
According to one aspect of the present application, there is provided a method of simultaneously installing two or more strings of coiled tubing simultaneously in a wellbore with the coiled tubing is connected to a pump or other downhole tool or device.
According to another aspect of the present application, there is provided a system of guiding one or more strings of coiled tubing into a wellbore as the strings of coiled tubing are pulled into the wellbore by another coiled tubing string. The present application discloses coiled tubing equipment for the insertion of the additional coiled tubing strings into the wellborn.
According to another aspect of the present application, there is provided a method for connecting two or more coiled tubing strings to a downhole device such as a hydraulic submersible pump which allows for fluid segregation between resident wellbore fluids and fluids introduced to the system to provide a means of powering or driving a bottom hole assembly or downhole device such as a hydraulic submersible pump.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the present application will now be described, by way of example only, with reference to the attached figures, wherein:
FIG. 1 is a schematic diagram of an exemplary hydraulic submersible pump;
FIG. 2 is a diagram of an exemplary coiled tubing installation;
FIG. 3A is a diagram of an exemplary shearable pump connecting means;
FIG. 3B is a diagram of the shearable pump connecting means of FIG. 3A in a sheared condition;
FIG. 3C is a partial section of the pump connecting means of FIG. 3A;
FIG. 3D is a diagram of another exemplary pump connecting means, and
FIG. 4 is a diagram of an exemplary wellhead configuration.
The same reference numerals are used in different figures to denote similar elements.

DETAILED DESCRIPTION OF THE DRAWINGS

Although the apparatus and methods of the present application have application to many oil and gas bearing formations, it has significant application to low pressure gas wells with liquid loading problems and even more specific application to coalbed methane gas wells. Low pressure gas wells and coalbed methane gas wells with liquid loading problems require the removal of water to increase or even allow gas production. A hydraulic submersible pump is one such device that is commonly used to effect that removal. In one embodiment, a hydraulic submersible pump requiring two sources of supply of hydraulic fluid, one to effect an upstroke of a piston device, and one to effect a downstroke of that same piston device, can be used to remove water or liquids from a wellbore. An exemplary hydraulic pump is described in Canadian Patent Number 2,453,072, although other suitable devices can be used with the apparatus and methods of the present application.
In one embodiment, the method of the present application has specific reference to the installation of a hydraulic submersible pump using continuous lengths of coiled tubing as both the conveyance means for a hydraulic fluid as the drive means, as well as a conveyance means to bring free water to surface. Three separate strings of coiled tubing are attached to a hydraulic submersible pump by way of a pump connecting means. The pump connecting means allows the ends of the coiled tubing strings to be attached to the pump, and for the flow paths of each coiled tubing string to be in communication with the appropriate flow path within the pump. In the common embodiment, the pump connection means allows hydraulic fluid to be circulated by a hydraulic fluid system at surface through two of the three strings and to hydraulically power the hydraulic pump. The third string of coiled tubing is attached to the outlet portion of the pump and conveys free water to surface by the hydraulic pump. The free water is produced at surface to a water collection system.
According to a method of the present application, three strings of coiled tubing are connected to a pump connection means at surface, and one of the strings of coiled tubing is used to pull the other two strings into the wellbore. One coiled tubing string is designated as the “master” string, and is run into the wellbore using a coiled tubing injector and associated gooseneck or guide arch. The master string is then used to pull the other two strings, known as “slave” strings, into the wellbore at about the same speed as the master string such that the potential for tensile parting or compressive buckling is minimized.
With reference to FIG. 1, in one embodiment, a hydraulic submersible pump assembly 101 is described that can be used for the removal of water from a wellbore. The pump assembly 101 is of a type described in Canadian Patent Number 2,453,072 which is incorporated herein by reference. In pump assembly 101, a piston assembly 111 is driven by hydraulic fluid 112 in a reciprocating manner by the application of reciprocating pressure. Two inlet drive lines 102 and 103 are each in fluid communication with opposite sides of the piston assembly 111, such that application of a positive pressure on one side of the piston with a corresponding release of pressure on the opposite side causes the piston to move in an upward or downward direction. In one embodiment, application of pressure and flow of hydraulic fluid 112 to the drive line 102 acts to fill the chamber 107. With a corresponding release of pressure allowing flow to surface through drive line 103, hydraulic fluid 112 is released from chamber 108 allowing the piston 111 to move in a downward direction. The downward direction of piston 111 causes a release of fluid 113 contained in chamber 110 through an outlet valve assembly 105 and into an outlet tubing 106. In one embodiment, the fluid 113 is wellbore water. The water 113 is drawn into chamber 110 through inlet valve assembly 104 during the previous cycle of the pump assembly 101. In that cycle, pressure and fluid was delivered to chamber 108 through drive line 103 with a corresponding release of fluid and pressure from drive line 102 and chamber 107. This cyclic operation is controlled by a pressure control device at surface (not shown).
With reference to FIG. 2, in one embodiment, a coiled tubing unit 201 is situated near and rigged onto a wellbore 202. The wellbore 202 is equipped with a master valve 203 for closing off the well and isolating wellbore fluids from surface. The coiled tubing unit 201 is equipped with a reel 204 for storing and running a string of coiled tubing 205 referred to as the master string. The master string corresponds to outlet tubing 106 in FIG. 1. A coiled tubing injector device 206 is suspended above the wellbore 202 by a crane 207. The master coil 205 is run or fed into the injector device 206 over and through a gooseneck device 207 known as the master gooseneck. A wellhead pressure control and hanging device 209, which is specially designed to receive three coiled tubing strings, is attached to the injector 206 and a stripper packoff device 299 by a lubricator device 208 for spacing. The master coil 205 is run through the injector device 206, stripper packoff device 299, the lubricator device 208 and a wellhead pressure control and hanging device 209. A master coil passing through the injector device 206, lubricator device 208 and stripper packoff device 299 exposes the end of the master coil 205 outside the wellhead pressure control and hanging device 209 to enable devices to be connected to the master coil 205.
The injector device 206 is fitted or equipped with a second gooseneck device 210 referred to as the slave gooseneck, which is fixed to the injector device 206 but is not used to guide the master coil 205 that has been fed through the injector device 206.
Two additional coiled tubing reels 211 are located near the wellbore 202, typically opposite the wellbore 202 from the location of the coiled tubing unit 201. Reels 211 are used to store two strings of coiled tubing 212, referred to as the slave strings and previously described in FIG. 1 as hydraulic drive lines 102 and 103. The slave strings 212 are guided over the slave gooseneck 210 and fed through the wellhead pressure control device 209 and the wellhead annular device 213. The wellhead pressure control device 209 is equipped with specific and separate cavities such that each of the slave strings 212 are isolated from each other in the wellhead pressure control and hanging device 209, and the slave strings 212 are further also isolated from the master string 205 in the wellhead pressure control device 209. This allows all three strings of coiled tubing (205 and 212) to each have dedicated pressure control to avoid leaks from the wellbore 202.
The wellhead pressure control and hanging device 209 contains one or more annular packoff devices for each slave string 212 and another annular packoff device for the master string 205. The annular packoff devices are described below in more detail with reference to FIG. 4.
In the described embodiment, each slave string 212 is run through two packoff devices during installation. The master coil 205 is run through a single annular packoff device. The annular packoff devices are activated by the application of hydraulic pressure and are common devices and are conventional devices in coiled tubing operations. Variations to the number of annular packoff devices for each string are possible, depending on the specific circumstances of the well.
The master string 205 would generally be of a larger diameter than the slave strings 212, and the slave strings 212 are generally of equal diameter to each other. In variations to this embodiment, the master string 205 may be of equal or lesser size to the slave strings. In one embodiment, the master string 205 is 1.25 inch diameter, and the slave strings 212 are each 1 inch diameter.
In this embodiment, both slave strings 212 are run into the wellbore over a common slave gooseneck 210, but each slave string 212 could have its own gooseneck as well, or a common guide arch could be configured with dual sets of rollers that keep the slave coils 212 separate from each other.
In operation, once the master string 205 and the slave strings 212 are fed through the wellhead pressure control device and hanging device 209, connection to a pumping means can be made. As the slave coils 212 are used to operate the pumping means 301 with hydraulic fluid, the slave coils 212 are filled with hydraulic fluid prior to making the connection to the pump connection means 302.
In preparation for this connection, the pumping means 301 is connected to a pump connection means 302, the master valve 203 is opened, the pumping means 301 and pump connection means 302 are lowered into the wellbore 202 and suspended above the wellhead annular device 213, and the wellhead annular device 213 is activated to isolate any well pressure from surface. At this stage, the pump connection means 302 can now be connected to the master coil 205 and the slave coils 212.
Referring to FIG. 3A, a hydraulic pumping means 301 is connected to the master string 205 and the slave strings 212 through a pump connecting means 302, which allows for fluid communication between the slave coils and the respective pump fluid-drive chambers, and the master coil and the respective pump fluid-exhaust chamber.
In the embodiment shown, the pump connecting means 302 is connected to the pump by a threaded connection 303. Internal feeder tubes 304 are connected to the pump by way of swagelok fittings, and are connected to the bottom portion of the pump connection means also by way of swagelok fittings 305. The feeder tubes 304 are in communication with the pump drive system (ie upper and lower piston chambers) to allow the pump to be cycled. The two slave strings 212 are fed through the upper portion of the pump connection means and connected to the pump connection means by swagelok fittings 306. The slave strings 212 transition through the pump connecting means 302 to the internal feeder tubes 305. The master coil 205 is attached to the top of the pump connection means 302 by a swagelok fitting 307. A chamber through the body of the pump connecting means 302 provides a flow path for well production as exhausted by the pump 301. The flow paths are further described below with reference to FIG. 3C.
The body of the pump connecting means 302 includes an extended cylindrical section 319 which permits pressure control devices such as blowout prevention devices to be closed or activated on section 319 and effect a pressure seal to isolate wellbore pressure from surface.
With reference to FIG. 3B, the pump connecting means is comprised of two distinct sections, an upper section 310 and a lower section 311. These are attached to each other by way of a conventional shear disconnect sub 308. The shear disconnect sub 308 is fitted with a plurality of shear screws 309 that provide a specific tensile load capability such that if subjected to a tensile load in excess of the combined capability of the shear screws 309, the pump connecting means 302 will disconnect into two sections and allow retrieval of the upper portion with the lower portion remaining in the wellborn.
The upper section 310 and lower section 311 are shown in FIG. 3B. To enable the two sections to be assembled and to provide a continuous flow path for each of the slave strings through the pump connection means 302, the lower section of the pump connection means 311 is constructed such that slave tubing stubs 312 protrude from the top of the lower section 311. Similarly, a master tubing stub 313 also protrudes from the top of the lower section 311 to allow for flow through the master string.
With reference now to FIG. 3C, the inner flow paths of the master string 205 and one of the slave strings 212 are described. The flow path 314 of the master string 205 extends through the pump connection means 302. To allow a pressure seal in the master flow path 314 over the master tubing stub 313, the upper section 310 of the pump connection means 302 is constructed with a stabbing tube 316 which stabs onto the master tubing stub 313 upon assembly. The stabbing tube 316 is a friction fit with o-ring devices 318 to effect a pressure seal for the mater flow path 314.
The flow paths 315 of each of the slave strings also extend through the pump connection means 302. The upper section 310 of the pump connection means 302 is constructed with stabbing tubes 317 which stab onto the slave tubing stubs 312 upon assembly. The stabbing tubes 317 are also friction fit with o-ring devices 318 to effect a pressure seal for the slave flow paths 315. This design therefore allows for a continuous flow path through the pump connection means 302 upon assembly while still allowing for a shear mechanism 308 within the assembly.
Referring to FIG. 3D, an alternate embodiment of the pump connecting means 302 is shown. This embodiment is similar to that shown in FIGS. 3A, 3B, and 3C, but is constructed as a singular section without the disconnect sub 308 or extended cylindrical section 319 as shown in the aforementioned figures. In the embodiment of FIG. 3D, the pump connecting means 302 is connected to the pump by a threaded connection 303. Internal feeder tubes 304 are connected to the pump by swagelok fittings, and are connected to the bottom portion of the pump connection means also swagelok fittings 305. The feeder tubes 304 are in communication with the pump drive system (ie upper and lower piston chambers) to allow the pump to be cycled. The two slave strings 212 are fed through the upper portion of the pump connection means and connected to the pump connection means by swagelok fittings 306. The slave strings 212 transition through the pump connecting means 302 to the internal feeder tubes 305. The master coil 205 is attached to the top of the pump connection means 302 by a swagelok fitting 307. A chamber through the body of the pump connecting means 302 provides a flow path for well production as exhausted by the pump 301. The flow paths are generally as those described with reference to FIG. 3C.
Referring back to FIG. 2, the hydraulic pumping means and pump connecting means are now connected to both slave coils 212 and the master coil 205 and suspended below the wellhead pressure control means 209 and ready for installation into the wellbore 202.
The injector means 206 is lowered to place the wellhead annular 213 and the wellhead pressure control means 209 to the master valve 203 and the wellhead annular 213 is connected to the master valve 203. This allows for pressure containment of the wellbore 202, but also allows the master coil 205 and slave coils 212 to be run into the wellbore 202 to land the pumping means 301 at the desired depth.
When coiled tubing is run into a wellbore, there is generally a positive weight acting on the coiled tubing string and this weight is measured by a weight indicator or load cell at the injector means. This positive weight confirms that the coiled tubing string is in a tension mode. There are situations that can develop that would result in a negative weight measured at the injector, which would confirm that the coiled tubing string was in a compressive mode. Compression of coiled tubing in a wellbore can lead to buckling, either sinusoidal or helical, and can result in damage to, or failure of, the coiled tubing string. In one embodiment, the weight of the master coil 205 experienced while running in hole with the slave coils 212 is controlled to maintain the master in a tensile mode. The slave reels 211 are each equipped with hydraulically operated systems which control the rate or speed at which the reels can be rotated. These controls are conventional devices in coiled tubing operations, and are similar to the hydraulic controls on the master reel 201.
While running in hole with the master coil 205, the hydraulic pressure of the slave reels 211 are controlled such that the weight measured by the injector means 206 is maintained at a level that is slightly below the calculated weight for the master coil 205. This ensures the slave coils 212 are landed in a slight tensile mode and minimizes or avoids the potential for helical or sinusoidal buckling.
The master coil 205 is typically transported to location on the main reel 204 of the coiled tubing unit 201 but can alternatively be run off a remote reel. Slave coils 212 can be transported on separate reels 211, or two slave coils on a common reel. Common reels can have a divider such that the reel is split to keep each coil separate but on the same reel, or the coils could simply be spooled carefully onto the same reel. In the embodiment of FIG. 2, the slave coils are transported to location and run into the wellbore off separate reels.
In the embodiment described above, the master coil 205 is run into the wellbore and pulls the slave strings 212 into the wellbore 202. The pump assembly is landed based on the depth as measured for the master coil. The master and slave coils are cut at surface and hung in the wellhead assembly, using the lower of the two annular packoffs for pressure control in the event of a wellhead leak, or in order to remove the strings in the future.
Referring to FIG. 4, the wellhead pressure control device 209 is now described. In the described embodiment, each slave string 212 is run through two packoff devices during installation, the upper annular packoff devices 401 being the primary well control means for each string while running in hole, and the lower annular packoff devices 402 being left on the wellhead after installation to provide well control during production operations. The master coil 205 is run through a single annular packoff device 403, as primary well control is provided byway of the stripper packoff device 299 under the injector means 206. Variations to the number of annular packoff devices for each string are possible, depending on the specific circumstances of the well. The embodiment of FIG. 4 shows a triple string wellhead assembly as provided by Select Energy Systems, which includes Select Part # 04-203-420-00-00 for the vertical access base, and Select 2590SS Coiled Tubing Hanger/Annular components for both the upper annular packoff devices 401 and the lower annular packoff devices 402 and 403.
In another embodiment of the system of the present invention, an injector head with three discreet sets of injector blocks is used, such that instead of the master string pulling the slaves into the wellbore, the injector delivers all three strings under a common injector drive.

Claims

1. A method of installing strings of coiled tubing into a wellbore comprising the steps of:

providing a first string of coiled tubing,

providing at least one other string of coiled tubing,

joining the first string of coiled tubing to the at least one other string of coiled tubing,

inserting the first string of coiled tubing into the wellbore whereby, the at least one other string of coiled tubing is inserted into the wellbore by the first string of coiled tubing.

2. A method according to claim 1 wherein the at least one other string of coiled tubing includes a second and third string of coiled tubing.

3. A method according to claim 2 wherein the first, second and third strings of coiled tubing are joined by a common connector.

4. A method according to claim 3 wherein the first string of coiled tubing is inserted into the wellbore by an injector.

5. A method according to claim 3 wherein the common connector joins free ends of the first, second and third strings of coiled tubing.

6. The method of claim 5 where the first string of coiled tubing is of larger diameter than the second or third strings of coiled tubing.

7. An apparatus for installing strings of coiled tubing together into a wellbore comprising:

an injector for inserting a first string of coiled tubing into the wellbore,

a common connector for joining at least one other string of coiled tubing with the first string of coiled tubing and whereby, insertion of the first string of coiled tubing into a wellbore causes insertion of the at least second string of coiled tubing into the wellbore.

8. An apparatus according to claim 7 wherein the common connector is adapted to join together a first, second and third string of coiled tubing and whereby, insertion of the first string of coiled tubing into a wellbore causes insertion of the second and third strings of coiled tubing into the wellbore.

9. The apparatus according to claim 8 wherein the first string of coiled tubing is guided into the injector by a first guide attached to the injector.

10. The apparatus according to claim 9 wherein the second and third strings of coiled tubing are guided into the wellbore by at least a second guide attached to the injector.

11. The apparatus according to claim 7 wherein the common connector is a connector for connecting the strings of coiled tubing to a bottom hole assembly.

12. The apparatus according to claim 11 wherein the bottom hole assembly is a pump.

13. The apparatus according to claim 12 wherein the pump connector includes two sections which are separable when subjected to a sufficient tensile loading.

14. The apparatus according to claim 13 wherein a first section of the pump connector joins the first, second and third coiled tubing sections and a second section is connectable to a bottom hole assembly.

15. The apparatus according to claim 14 further including a separate wellhead pressure controller for providing one or more barriers between the wellbore and the atmosphere.

16. An apparatus for inserting at least three coiled tubing strings into a wellbore, the apparatus comprising:

an injector for inserting a master coiled tubing string into a wellbore,

a connector for affixing a master coiled tubing string to two slave coiled tubing strings whereby insertion of the master coiled tubing string into a wellbore causes the slave coiled tubing strings to be inserted together with the master coiled tubing string.

17. An apparatus according to claim 16 further including a first guide connected to the injector for guiding the master coiled tubing string into the injector.

18. An apparatus according to claim 17 further including at least a second guide for guiding the slave coiled tubing strings into the injector.

19. An apparatus according to claim 18 further including a well head pressure control and hanging device for receiving the master and slave coiled tubing strings.

20. The apparatus of claim 19 wherein the pump connecting means includes a section for permitting sealing with a pressure sealing means to be activated against that section of common diameter.