CA2303995C - Method for emplacing a coil tubing string in a well - Google Patents
Method for emplacing a coil tubing string in a well Download PDFInfo
- Publication number
- CA2303995C CA2303995C CA 2303995 CA2303995A CA2303995C CA 2303995 C CA2303995 C CA 2303995C CA 2303995 CA2303995 CA 2303995 CA 2303995 A CA2303995 A CA 2303995A CA 2303995 C CA2303995 C CA 2303995C
- Authority
- CA
- Canada
- Prior art keywords
- tubing string
- string
- bottom end
- coil tubing
- wellbore
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired - Lifetime
Links
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
- E21B19/22—Handling reeled pipe or rod units, e.g. flexible drilling pipes
Abstract
The bottom end of a coil tubing string is secured to the bottom end of a primary tubing string at ground surface. Usually the primary tubing string will be of larger diameter and is therefore stronger and stiffer than the coil tubing string. The strings are secured together with a locking assembly. This assembly comprises two interlocking members, one connected with each string. One of the interlocking members is meltable when exposed to elevated temperature. The primary tubing string and the coil tubing string are run together into the desired position in the wellbore. The primary tubing string acts to drag the coil tubing string along with it. Heat is then used to melt the interlocking member so that the strings can be separated. The heat can be provided by circulating steam or hot water or oil down to the assembly. Alternatively the downhole formation temperature may be sufficient to induce melting. Once separated, each string can be pulled or moved independently. 10
Description
1 "METHOD FOR EMPLACING A COIL TUBING STRING
2 IN A WELL"
3
4 FIELD OF THE INVENTION
The present invention relates to a means and method for emplacing a 6 string of coil tubing in a wellbore.
9 It is common oilfield practice to emplace a string of coil tubing in a completed oil or gas wellbore. The coil tubing may be used for any of a 11 variety of purposes. For example, it can be used for chemical injection;
steam 12 injection, service as a bubble tube for measuring downhole pressure, sand 13 clean-out, solvent spotting or circulation, or for carrying sensor 14 instrumentation for measuring downhole pressure or temperature. The present invention was developed in connection with using coil tubing for 16 carrying sensor instrumentation downhole.
17 Coil tubing has a relatively small diameter. The diameter can vary 18 between 118 inch and 2 inch. As a result, a string of coil tubing is pretty 19 flexible. It has a tendency to spiral or corkscrew as it is being run into a wellbore. Also, it does not lend itself to being forced through wellbore tight 21 spots, sand plugs and the like. These problems are magnified when trying to 22 run the coil tubing in to the toe end of a horizontal wellbore, such as a 23 wellbore to be used in a steam-assisted gravity drainage ("SAGDn) project.
(A
24 horizontal wellbore usually extends downwardly from ground surface to a hydrocarbon-containing reservoir and then bends to extend, generally 26 horizontally, into the reservoir. The wellbore is described as having a "heel"
27 (at the bend) and a "toe" (at the far end of the wellbore). The section of 1 wellbore between heel and toe is often referred to as the °production 2 interval").
3 As previously indicated, it is known to emplace a coil tubing 4 instrumentation string in the horizontal section of a wellbore to measure formation temperature or pressure and relay this information to ground 6 surface through cable means. From this information, the operator can 7 develop a temperature or pressure profile extending the length of the 8 production interval. However this requires that the string extend from the heel 9 to the toe of the horizontal wellbore section.
So one problem to be addressed is how to better insert a coil tubing 11 string to the desired landing point in a wellbore. In the case of a wellbore 12 having a horizontal production interval, the problem is how to better insert the 13 string so that it reaches the toe end of the wellbore. However, the solution to 14 the problem needs to ensure that, once the coil tubing string is in place downhole, it is present as a freely and independently movable string.
18 In accordance with the invention, there is provided a locking assembly 19 comprising two interlocking members. One member is secured to the bottom end of a relatively large diameter and substantially rigid production or steam 21 injection tubing string (hereinafter referred to as the "primary string").
The 22 other member is secured to the bottom end of a relatively small diameter and 23 more flexible coil tubing string. The locking assembly is used to secure the 24 bottom ends of the two strings together at ground surface. The strings are then run into the wellbore together. The primary string functions to pull the i i i 1 coil tubing string along with it. The primary string is better able to penetrate 2 through obstructions in the wellbore and reach the desired landing point.
3 Thus the likelihood of landing the coil tubing string at the desired landing point 4 is improved. In many cases the desired landing point is in the toe end of a horizontal wellbore.
6 One of the interlocking members is formed of a material which melts 7 when exposed downhole to an elevated temperature for sufficient time. The 8 elevated temperature can be provided by introducing, as by circulating, a hot 9 fluid, such as steam, into the vicinity of the shear sub. Alternatively, the reservoir itself may be at a temperature sufficient to cause melting.
11 In either case, once the shear sub is landed downhole and exposed to 12 elevated temperature for sufficient time to melt the meltable member, the two 13 strings can then be separated.
14 The invention gives the well operator the opportunity to pull either string independently after deployment and separation. If the coil tubing string 16 is an instrumentation coil tubing string, it can be independently removed for 17 repairs or for transfer to another well. If the primary string needs to be 18 removed or landed at another point along the wellbore, without moving the 19 secondary string, this is now feasible.
In one aspect, the invention is a method for emplacing a coil tubing 21 string having a bottom end in a wellbore having a horizontal section, said 22 section having toe and heel ends, comprising providing at ground surface a 23 primary tubing string and a coil tubing string, each having a bottom end, the 24 primary tubing string having a larger diameter and being stronger and more rigid than the coil tubing string; securing the coil tubing string bottom end to ~E3097617.DOC;1 }
i 1 the primary tubing string bottom end with first means secured to one string 2 bottom end and second means secured to the other string bottom end, said 3 first and second means being interlocked by a pair of solid members, one of 4 which is meltable at an elevated temperature downhole; running the two strings into the borehole with the coil tubing string secured to the primary 6 tubing string and landing their bottom ends adjacent the toe end of the 7 wellbore; melting the meltable member; and separating the coil tubing string 8 from the primary tubing string.
9 In another aspect, the invention is an assembly for running into a wellbore, comprising a coil tubing string having a bottom end; a tubing string 11 having a bottom end; the primary tubing string having a larger diameter than 12 the coil tubing string; and a locking assembly securing the two bottom ends 13 together, said assembly comprising first means secured to one string bottom 14 end and second means secured to the other string bottom end, said first and 1 S second means being interlocked by a pair of solid members, one of the 16 members being convertible from a solid form to a liquid form when exposed to 17 a liquefying agent.
19 Figure 1 is a schematic showing a horizontal wellbore having a primary tubing string and a string of coiled tubing positioned therein and landed 21 adjacent the toe end of the wellbore, the two strings being secured together at 22 their bottom ends by a locking assembly;
23 Figure 2 is a plan sectional view showing the locking assembly ; and ~E3097617.DOC;1 f 1 Figure 3 is an exploded plan view, partly in section, of the locking 2 assembly of Figure 2.
4 Figure 1 shows a horizontal well 1, having riser and horizontal sections 2,3, extending from ground surface 4 and penetrating a hydrocarbon-6 containing reservoir 5. The well 1 is completed with casing 6 and a perforated 7 production liner 7. A wellbore 8 is formed by the casing and liner. The 8 wellbore 8 has heel and toe ends 9, 10. A primary tubing string 11, such as a 9 production or steam injection tubing string, is positioned in the wellbore 8 at its toe end 10. A substantially co-extensive string 12 of coil tubing is positioned 11 beside the primary tubing string 11. The bottom ends 13, 14 of the strings 11, 12 12 are secured together by a locking assembly 15.
13 The locking assembly 15 comprises a shear sub 16, which is welded to 14 the outer surface of the primary tubing string 11, and a separable assembly 17 which is threadably connected with the coil tubing string 12. The shear 16 sub 16 and separable assembly 17 interlock, as described below, to secure 17 the two strings 11, 12 together.
18 More particularly, the shear sub 16 is an elongated cylindrical steel 19 body 18 having a tubular rear end side wall 19 forming an axial chamber 20, open at its rear end. The side wall 19 has perforations 21 and terminates with 21 a threaded segment 22.
The present invention relates to a means and method for emplacing a 6 string of coil tubing in a wellbore.
9 It is common oilfield practice to emplace a string of coil tubing in a completed oil or gas wellbore. The coil tubing may be used for any of a 11 variety of purposes. For example, it can be used for chemical injection;
steam 12 injection, service as a bubble tube for measuring downhole pressure, sand 13 clean-out, solvent spotting or circulation, or for carrying sensor 14 instrumentation for measuring downhole pressure or temperature. The present invention was developed in connection with using coil tubing for 16 carrying sensor instrumentation downhole.
17 Coil tubing has a relatively small diameter. The diameter can vary 18 between 118 inch and 2 inch. As a result, a string of coil tubing is pretty 19 flexible. It has a tendency to spiral or corkscrew as it is being run into a wellbore. Also, it does not lend itself to being forced through wellbore tight 21 spots, sand plugs and the like. These problems are magnified when trying to 22 run the coil tubing in to the toe end of a horizontal wellbore, such as a 23 wellbore to be used in a steam-assisted gravity drainage ("SAGDn) project.
(A
24 horizontal wellbore usually extends downwardly from ground surface to a hydrocarbon-containing reservoir and then bends to extend, generally 26 horizontally, into the reservoir. The wellbore is described as having a "heel"
27 (at the bend) and a "toe" (at the far end of the wellbore). The section of 1 wellbore between heel and toe is often referred to as the °production 2 interval").
3 As previously indicated, it is known to emplace a coil tubing 4 instrumentation string in the horizontal section of a wellbore to measure formation temperature or pressure and relay this information to ground 6 surface through cable means. From this information, the operator can 7 develop a temperature or pressure profile extending the length of the 8 production interval. However this requires that the string extend from the heel 9 to the toe of the horizontal wellbore section.
So one problem to be addressed is how to better insert a coil tubing 11 string to the desired landing point in a wellbore. In the case of a wellbore 12 having a horizontal production interval, the problem is how to better insert the 13 string so that it reaches the toe end of the wellbore. However, the solution to 14 the problem needs to ensure that, once the coil tubing string is in place downhole, it is present as a freely and independently movable string.
18 In accordance with the invention, there is provided a locking assembly 19 comprising two interlocking members. One member is secured to the bottom end of a relatively large diameter and substantially rigid production or steam 21 injection tubing string (hereinafter referred to as the "primary string").
The 22 other member is secured to the bottom end of a relatively small diameter and 23 more flexible coil tubing string. The locking assembly is used to secure the 24 bottom ends of the two strings together at ground surface. The strings are then run into the wellbore together. The primary string functions to pull the i i i 1 coil tubing string along with it. The primary string is better able to penetrate 2 through obstructions in the wellbore and reach the desired landing point.
3 Thus the likelihood of landing the coil tubing string at the desired landing point 4 is improved. In many cases the desired landing point is in the toe end of a horizontal wellbore.
6 One of the interlocking members is formed of a material which melts 7 when exposed downhole to an elevated temperature for sufficient time. The 8 elevated temperature can be provided by introducing, as by circulating, a hot 9 fluid, such as steam, into the vicinity of the shear sub. Alternatively, the reservoir itself may be at a temperature sufficient to cause melting.
11 In either case, once the shear sub is landed downhole and exposed to 12 elevated temperature for sufficient time to melt the meltable member, the two 13 strings can then be separated.
14 The invention gives the well operator the opportunity to pull either string independently after deployment and separation. If the coil tubing string 16 is an instrumentation coil tubing string, it can be independently removed for 17 repairs or for transfer to another well. If the primary string needs to be 18 removed or landed at another point along the wellbore, without moving the 19 secondary string, this is now feasible.
In one aspect, the invention is a method for emplacing a coil tubing 21 string having a bottom end in a wellbore having a horizontal section, said 22 section having toe and heel ends, comprising providing at ground surface a 23 primary tubing string and a coil tubing string, each having a bottom end, the 24 primary tubing string having a larger diameter and being stronger and more rigid than the coil tubing string; securing the coil tubing string bottom end to ~E3097617.DOC;1 }
i 1 the primary tubing string bottom end with first means secured to one string 2 bottom end and second means secured to the other string bottom end, said 3 first and second means being interlocked by a pair of solid members, one of 4 which is meltable at an elevated temperature downhole; running the two strings into the borehole with the coil tubing string secured to the primary 6 tubing string and landing their bottom ends adjacent the toe end of the 7 wellbore; melting the meltable member; and separating the coil tubing string 8 from the primary tubing string.
9 In another aspect, the invention is an assembly for running into a wellbore, comprising a coil tubing string having a bottom end; a tubing string 11 having a bottom end; the primary tubing string having a larger diameter than 12 the coil tubing string; and a locking assembly securing the two bottom ends 13 together, said assembly comprising first means secured to one string bottom 14 end and second means secured to the other string bottom end, said first and 1 S second means being interlocked by a pair of solid members, one of the 16 members being convertible from a solid form to a liquid form when exposed to 17 a liquefying agent.
19 Figure 1 is a schematic showing a horizontal wellbore having a primary tubing string and a string of coiled tubing positioned therein and landed 21 adjacent the toe end of the wellbore, the two strings being secured together at 22 their bottom ends by a locking assembly;
23 Figure 2 is a plan sectional view showing the locking assembly ; and ~E3097617.DOC;1 f 1 Figure 3 is an exploded plan view, partly in section, of the locking 2 assembly of Figure 2.
4 Figure 1 shows a horizontal well 1, having riser and horizontal sections 2,3, extending from ground surface 4 and penetrating a hydrocarbon-6 containing reservoir 5. The well 1 is completed with casing 6 and a perforated 7 production liner 7. A wellbore 8 is formed by the casing and liner. The 8 wellbore 8 has heel and toe ends 9, 10. A primary tubing string 11, such as a 9 production or steam injection tubing string, is positioned in the wellbore 8 at its toe end 10. A substantially co-extensive string 12 of coil tubing is positioned 11 beside the primary tubing string 11. The bottom ends 13, 14 of the strings 11, 12 12 are secured together by a locking assembly 15.
13 The locking assembly 15 comprises a shear sub 16, which is welded to 14 the outer surface of the primary tubing string 11, and a separable assembly 17 which is threadably connected with the coil tubing string 12. The shear 16 sub 16 and separable assembly 17 interlock, as described below, to secure 17 the two strings 11, 12 together.
18 More particularly, the shear sub 16 is an elongated cylindrical steel 19 body 18 having a tubular rear end side wall 19 forming an axial chamber 20, open at its rear end. The side wall 19 has perforations 21 and terminates with 21 a threaded segment 22.
5 i
6 1 The separable assembly 17 comprises a steel shaft 23 having an 2 expanded diameter head 24 at its front end and a threaded rear end 25. The 3 shaft 23 is received in the axial chamber 20 of the first member 16 and its rear 4 end 25 protrudes therefrom. A tubular plastic sleeve 26 is positioned concentrically around the shaft 23 and abuts the head 24. An internally 6 threaded cap 27 is screwed onto the threaded segment 22 of the shear sub
7 16. The end wall 28 of the cap 27 forms a central opening 29 through which
8 the rear end 25 of the shaft 23 protrudes. The cap end wall opening 29 is
9 sized to allow the shaft 23 and head 24 to pass therethrough, but not the solid sleeve 26. The shaft rear end 25 is threaded into a coupling 30 which 11 threadably connects with the coil tubing string 12.
12 From the foregoing it will be understood that the shaft 23, sleeve 26 13 and cap end wall 28 provide two interlocking members, tieing together means 14 secured to the primary tubing string 11 and means secured to the coil tubing string 12. One of these interlocking members is readily meltable at downhole 16 elevated temperature.
17 The plastic selected for the shear sleeve 26 should be strong enough 18 to withstand the compressive loading that one would anticipate would occur 19 as the primary tubing string 11 drags the coil tubing string 12 along through the wellbore 8. It should also melt when subjected to the expected downhole 21 elevated temperature. An appropriate selection of the plastic or other suitable 22 material can be made without difficulty by one of ordinary skill in the art. By 23 way of example, for a steam injection well having a depth of 500 meters we 24 selected a plastic available from Plasti Fab Industries, Alberta, under the }E3097617.DOC;1 }
I i 1 designation low-density polyethylene, having a compressive strength of 4000 2 psi and a melting temperature of 95°C.
3 When so melted, the plastic can drain out of the chamber 17 through 4 the side openings 20 and the coil tubing string 11 can be pulled a short distance to separate the assembly 17 from the shear sub 16.
6 In the practise of the invention, the bottom ends 13, 14 of the primary 7 and coil tubing strings 11, 12 are secured together at ground surface with the 8 locking assembly 15. This may be done by assembling the separable 9 assembly 17 and shear sub 16, threadably connecting the coupling 30 to the bottom end 14 of the coil tubing string 12 and welding the body 18 to the 11 bottom end 13 of the primary string 11. The two strings are then run together 12 into the wellbore 8 and landed in the toe end 10. Steam is introduced into the 13 toe end of the wellbore, to melt the shear sleeve 26. The coil tubing string 12 14 can then be moved to withdraw the shaft 23 and head 24 from the axial chamber 20 and separate or disconnect the two strings.
16 The invention has been described in the context of using heat 17 downhole to melt one of the solid interlocking members of the locking 18 assembly 15. However it is within the scope of the invention to form one of 19 the interlocking members of a solid material convertible to a liquid form when exposed to a liquefying agent such as a solvent.
~E3097617.DOC;1 }
12 From the foregoing it will be understood that the shaft 23, sleeve 26 13 and cap end wall 28 provide two interlocking members, tieing together means 14 secured to the primary tubing string 11 and means secured to the coil tubing string 12. One of these interlocking members is readily meltable at downhole 16 elevated temperature.
17 The plastic selected for the shear sleeve 26 should be strong enough 18 to withstand the compressive loading that one would anticipate would occur 19 as the primary tubing string 11 drags the coil tubing string 12 along through the wellbore 8. It should also melt when subjected to the expected downhole 21 elevated temperature. An appropriate selection of the plastic or other suitable 22 material can be made without difficulty by one of ordinary skill in the art. By 23 way of example, for a steam injection well having a depth of 500 meters we 24 selected a plastic available from Plasti Fab Industries, Alberta, under the }E3097617.DOC;1 }
I i 1 designation low-density polyethylene, having a compressive strength of 4000 2 psi and a melting temperature of 95°C.
3 When so melted, the plastic can drain out of the chamber 17 through 4 the side openings 20 and the coil tubing string 11 can be pulled a short distance to separate the assembly 17 from the shear sub 16.
6 In the practise of the invention, the bottom ends 13, 14 of the primary 7 and coil tubing strings 11, 12 are secured together at ground surface with the 8 locking assembly 15. This may be done by assembling the separable 9 assembly 17 and shear sub 16, threadably connecting the coupling 30 to the bottom end 14 of the coil tubing string 12 and welding the body 18 to the 11 bottom end 13 of the primary string 11. The two strings are then run together 12 into the wellbore 8 and landed in the toe end 10. Steam is introduced into the 13 toe end of the wellbore, to melt the shear sleeve 26. The coil tubing string 12 14 can then be moved to withdraw the shaft 23 and head 24 from the axial chamber 20 and separate or disconnect the two strings.
16 The invention has been described in the context of using heat 17 downhole to melt one of the solid interlocking members of the locking 18 assembly 15. However it is within the scope of the invention to form one of 19 the interlocking members of a solid material convertible to a liquid form when exposed to a liquefying agent such as a solvent.
~E3097617.DOC;1 }
Claims (4)
EXCLUSIVE PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS
FOLLOWS:
1. A method for emplacing a coil tubing string having a bottom end in a wellbore having a horizontal section, said section having toe and heel ends, comprising:
providing at ground surface a primary tubing string and a coil tubing string, each having a bottom end, the primary tubing string having a larger diameter and being stronger and more rigid than the coil tubing string;
securing the coil tubing string bottom end to the primary tubing string bottom end with first means secured to one string bottom end and second means secured to the other string bottom end, said first and second means being interlocked by a pair of solid members, one of which is meltable at an elevated temperature downhole;
running the two strings into the borehole with the coil tubing string secured to the primary tubing string and landing their bottom ends adjacent the toe end of the wellbore;
melting the meltable member; and~
separating the coil tubing string from the primary tubing string.
providing at ground surface a primary tubing string and a coil tubing string, each having a bottom end, the primary tubing string having a larger diameter and being stronger and more rigid than the coil tubing string;
securing the coil tubing string bottom end to the primary tubing string bottom end with first means secured to one string bottom end and second means secured to the other string bottom end, said first and second means being interlocked by a pair of solid members, one of which is meltable at an elevated temperature downhole;
running the two strings into the borehole with the coil tubing string secured to the primary tubing string and landing their bottom ends adjacent the toe end of the wellbore;
melting the meltable member; and~
separating the coil tubing string from the primary tubing string.
2. The method as set forth in claim 1 comprising:
introducing steam in or through the horizontal section of the wellbore to create an elevated temperature in said section sufficient to melt the meltable member.
introducing steam in or through the horizontal section of the wellbore to create an elevated temperature in said section sufficient to melt the meltable member.
3. An assembly for running into a wellbore, comprising:
a coil tubing string having a bottom end;
a primary tubing string having a bottom end;
the primary tubing string having a larger diameter than the coil tubing string; and a locking assembly securing the two bottom ends together, said assembly comprising first means secured to one string bottom end and second means secured to the other string bottom end, said first and second means being interlocked by a pair of solid members, one of the members being convertible from a solid form to a liquid form when exposed to a liquefying agent.
a coil tubing string having a bottom end;
a primary tubing string having a bottom end;
the primary tubing string having a larger diameter than the coil tubing string; and a locking assembly securing the two bottom ends together, said assembly comprising first means secured to one string bottom end and second means secured to the other string bottom end, said first and second means being interlocked by a pair of solid members, one of the members being convertible from a solid form to a liquid form when exposed to a liquefying agent.
4. The assembly as set forth in claim 2 wherein the convertible member is meltable when exposed to downhole steam.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA 2303995 CA2303995C (en) | 2000-04-05 | 2000-04-05 | Method for emplacing a coil tubing string in a well |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA 2303995 CA2303995C (en) | 2000-04-05 | 2000-04-05 | Method for emplacing a coil tubing string in a well |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2303995A1 CA2303995A1 (en) | 2001-10-05 |
| CA2303995C true CA2303995C (en) | 2004-06-29 |
Family
ID=4165791
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA 2303995 Expired - Lifetime CA2303995C (en) | 2000-04-05 | 2000-04-05 | Method for emplacing a coil tubing string in a well |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA2303995C (en) |
-
2000
- 2000-04-05 CA CA 2303995 patent/CA2303995C/en not_active Expired - Lifetime
Also Published As
| Publication number | Publication date |
|---|---|
| CA2303995A1 (en) | 2001-10-05 |
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Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request | ||
| MKEX | Expiry |
Effective date: 20200405 |