CA2901074A1 - Sleeve system for use in wellbore completion operations - Google Patents
Sleeve system for use in wellbore completion operations Download PDFInfo
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- CA2901074A1 CA2901074A1 CA2901074A CA2901074A CA2901074A1 CA 2901074 A1 CA2901074 A1 CA 2901074A1 CA 2901074 A CA2901074 A CA 2901074A CA 2901074 A CA2901074 A CA 2901074A CA 2901074 A1 CA2901074 A1 CA 2901074A1
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- sleeve
- bha
- tool
- sleeves
- casing
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Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/06—Valve arrangements for boreholes or wells in wells
- E21B34/14—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
- E21B23/004—Indexing systems for guiding relative movement between telescoping parts of downhole tools
- E21B23/006—"J-slot" systems, i.e. lug and slot indexing mechanisms
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
- E21B2200/06—Sleeve valves
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- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Earth Drilling (AREA)
Abstract
A downhole tool is disclosed for shifting a sleeve. The downhole tool utilizes a first slip assembly, a second slip assembly located downhole to the first slip assembly, and a J-slot mechanism The J-slot mechanism alternates actuation of the first and second slip assemblies for selectively opening and closing the sleeve.
Description
"SLEEVE SYSTEM FOR USE IN WELLBORE COMPLETION OPERATIONS"
FIELD
Embodiments relate to apparatus and methods for completion of a wellbore and, more particularly, to apparatus and methods for completing a wellbore and fracturing a formation therethrough, utilizing sleeve valves which are openable and closeable.
BACKGROUND
It is well known to line wellbores with liners or casing and the like and, thereafter, to create flowpaths through the casing to permit fluids, such as fracturing fluids, to reach the formation therebeyond.
One such conventional method for creating flowpaths is to perforate the casing using apparatus, such as a perforating gun, which typically utilizes an explosive charge to create localized openings through the casing.
Alternatively, the casing can include pre-machined ports, located at intervals therealong. The ports are typically sealed during insertion of the casing into the wellbore, such as by a dissolvable plug, a burst port assembly, a sleeve or the like. Optionally, the casing can thereafter be cemented into the wellbore, the cement being placed in an annulus between the wellbore and the casing.
Thereafter, the ports are typically selectively opened by removing the sealing means to permit fluids, such as fracturing fluids, to reach the formation.
Typically, when sleeves are used to seal the ports, the sleeves are releasably retained thereover and can be actuated to slide within the casing to open and close the respective ports. Many different types of sleeves and apparatus to actuate the sleeves are known in the industry. Fluids are directed into the formation through the open ports. At least one sealing means, such as a packer, is employed to isolate the balance of the wellbore below the sleeve from the treatment fluids.
A variety of tools are known for actuating sleeves in ported subs including the use of shifting tools, profiled tools and packers. In US Patent 6,024,173 to Patel and assigned to Schlumberger, a shifting tool and a position locator is disclosed for locating a downhole device and engaging a packer element within a moveable member and operating the device using an applied axial force to shift the member.
In US Patent 6,631,768 to Patel, a variety of other shifting tools known for shifting sleeves are discussed.
US published application 2006/0124310 to Schlumberger Reservoir Completions teaches that it is known to use casing valves incorporated within a casing string which is cemented into the wellbore. The casing valves incorporate a sleeve within the bore of the casing or optionally on the outside of the casing, to control flow through ports in the casing. The sleeve is shiftable from an open port position to a closed port position and from a closed port position to an open port position. Shifting of the sleeve can be accomplished hydraulically by latching a plug in the sleeve and pressuring the bore thereabove or mechanically by engaging the sleeve with a shifting tool deployed on coiled tubing.
FIELD
Embodiments relate to apparatus and methods for completion of a wellbore and, more particularly, to apparatus and methods for completing a wellbore and fracturing a formation therethrough, utilizing sleeve valves which are openable and closeable.
BACKGROUND
It is well known to line wellbores with liners or casing and the like and, thereafter, to create flowpaths through the casing to permit fluids, such as fracturing fluids, to reach the formation therebeyond.
One such conventional method for creating flowpaths is to perforate the casing using apparatus, such as a perforating gun, which typically utilizes an explosive charge to create localized openings through the casing.
Alternatively, the casing can include pre-machined ports, located at intervals therealong. The ports are typically sealed during insertion of the casing into the wellbore, such as by a dissolvable plug, a burst port assembly, a sleeve or the like. Optionally, the casing can thereafter be cemented into the wellbore, the cement being placed in an annulus between the wellbore and the casing.
Thereafter, the ports are typically selectively opened by removing the sealing means to permit fluids, such as fracturing fluids, to reach the formation.
Typically, when sleeves are used to seal the ports, the sleeves are releasably retained thereover and can be actuated to slide within the casing to open and close the respective ports. Many different types of sleeves and apparatus to actuate the sleeves are known in the industry. Fluids are directed into the formation through the open ports. At least one sealing means, such as a packer, is employed to isolate the balance of the wellbore below the sleeve from the treatment fluids.
A variety of tools are known for actuating sleeves in ported subs including the use of shifting tools, profiled tools and packers. In US Patent 6,024,173 to Patel and assigned to Schlumberger, a shifting tool and a position locator is disclosed for locating a downhole device and engaging a packer element within a moveable member and operating the device using an applied axial force to shift the member.
In US Patent 6,631,768 to Patel, a variety of other shifting tools known for shifting sleeves are discussed.
US published application 2006/0124310 to Schlumberger Reservoir Completions teaches that it is known to use casing valves incorporated within a casing string which is cemented into the wellbore. The casing valves incorporate a sleeve within the bore of the casing or optionally on the outside of the casing, to control flow through ports in the casing. The sleeve is shiftable from an open port position to a closed port position and from a closed port position to an open port position. Shifting of the sleeve can be accomplished hydraulically by latching a plug in the sleeve and pressuring the bore thereabove or mechanically by engaging the sleeve with a shifting tool deployed on coiled tubing.
2 In Canadian Patents 2,738,907 and 2,693,676, both to NCS Oilfield Services Canada Inc., a bottom hole assembly (BHA) is deployed at an end of coiled tubing and located adjacent a ported sub by a sleeve locator. The BHA
has a sealing member and an anchor such as a releasable bridge plug or well packer, which are set inside the ported sub, actuable for shifting a sliding sleeve and opening ports to the wellbore. From an uphole end, the BHA is connected to coiled tubing, has a fluid cutting assembly (jet cutting tool), a check valve for actuating the jet cutting tool, a bypass/equalization valve and the sealing member, the releasable anchor and the sleeve locator. A multifunction valve, including reverse circulation and pressure equalization, is positioned between the abrasive fluid jetting assembly and the sealing element. Set down on the coiled tubing closes the multifunction valve, blocking fluid communication to the tubing below the sealing member, and aligning ports in the valve for reverse circulation between the annulus and one way flow up the coiled tubing through the check valve. Pull up on the coiled tubing opens the multifunction valve to permit flow through a port in the valve between the annulus and the tubing, below the sealing member, for equalization. Flow is also through the port in the valve between the annulus and one way flow up the coiled tubing, for reverse circulation. The check valve prevents fluid delivered through the coiled tubing from moving beyond the jetting assembly. Thus, fluid delivered through the coiled tubing is only used to cut perforations. Treatment fluid, such as for fracturing, is delivered through the annulus, between the BHA and the casing, to the ports opened by the sleeve.
has a sealing member and an anchor such as a releasable bridge plug or well packer, which are set inside the ported sub, actuable for shifting a sliding sleeve and opening ports to the wellbore. From an uphole end, the BHA is connected to coiled tubing, has a fluid cutting assembly (jet cutting tool), a check valve for actuating the jet cutting tool, a bypass/equalization valve and the sealing member, the releasable anchor and the sleeve locator. A multifunction valve, including reverse circulation and pressure equalization, is positioned between the abrasive fluid jetting assembly and the sealing element. Set down on the coiled tubing closes the multifunction valve, blocking fluid communication to the tubing below the sealing member, and aligning ports in the valve for reverse circulation between the annulus and one way flow up the coiled tubing through the check valve. Pull up on the coiled tubing opens the multifunction valve to permit flow through a port in the valve between the annulus and the tubing, below the sealing member, for equalization. Flow is also through the port in the valve between the annulus and one way flow up the coiled tubing, for reverse circulation. The check valve prevents fluid delivered through the coiled tubing from moving beyond the jetting assembly. Thus, fluid delivered through the coiled tubing is only used to cut perforations. Treatment fluid, such as for fracturing, is delivered through the annulus, between the BHA and the casing, to the ports opened by the sleeve.
3 Incorporation of the sealing member, the releasable anchor and the sleeve locator in the BHA, all of which must be cooperatively locatable within the sleeve housing, requires a sleeve housing of significant length and corresponding expense. Further, without additional components, the releaseable anchoring system is generally limited to downhole actuation of the specific sleeve.
There is interest in the industry for robust apparatus and methods of performing completion operations which are relatively simple, reliable, that could provide sleeve actuation, both to open and close the sleeve and which reduce the overall costs involved.
SUMMARY
According to embodiments taught herein, a tool having opposing slips is used to selectively open and close sleeves in casing in a wellbore.
Bottomhole assemblies (BHA) incorporating the opposing slips are conveyed using coiled tubing or jointed tubing. There are technical advantages to the use of coiled tubing-conveyed or jointed tubing-conveyed systems to manipulate a large number of sleeves installed along casing, which is cemented or not cemented into the wellbore, in vertical, deviated or horizontal oil or gas wells.
Embodiments are discussed further herein in the context of coiled tubing-conveyed systems, however as one of skill will appreciate from the description, such systems can also be conveyed using jointed tubing.
There is interest in the industry for robust apparatus and methods of performing completion operations which are relatively simple, reliable, that could provide sleeve actuation, both to open and close the sleeve and which reduce the overall costs involved.
SUMMARY
According to embodiments taught herein, a tool having opposing slips is used to selectively open and close sleeves in casing in a wellbore.
Bottomhole assemblies (BHA) incorporating the opposing slips are conveyed using coiled tubing or jointed tubing. There are technical advantages to the use of coiled tubing-conveyed or jointed tubing-conveyed systems to manipulate a large number of sleeves installed along casing, which is cemented or not cemented into the wellbore, in vertical, deviated or horizontal oil or gas wells.
Embodiments are discussed further herein in the context of coiled tubing-conveyed systems, however as one of skill will appreciate from the description, such systems can also be conveyed using jointed tubing.
4 In embodiments, the sleeves are manipulated to open or close as desired, for a variety of reasons, without tripping the tool. Advantages of this technology include the following:
= ability to open a selected sleeve before the frac operation commences to provide access to the reservoir, while isolating the rest of the well and to close the previously opened sleeve after the frac treatment, if desired, to isolate the newly stimulated zone to:
o prevent cross flow from the newly frac'd stage to previous stimulated stages;
o allow the frac to "heal", minimizing proppant, such as sand, flow back into the well while permitting the frac to settle around the proppant and forming a flow channel therethrough;
o open and close selected sleeves - can be done in any sequence within the wellbore; from heel to toe, from toe to heel or at any sequence of stages as desired.
= ability to close sleeves during the life of the well to control unwanted production from a particular stage or stages. One such example is the prevention or minimizing of water production in a water flood operation.
o fields or plays undergoing water flood development typically include wells that are injectors and producers. Water flow through the reservoir can be determined by several industry existing methods, ie.
production logging, radioactive/chemical tracers etc.
Once the location of water flow is determined, an operator can selectively close
= ability to open a selected sleeve before the frac operation commences to provide access to the reservoir, while isolating the rest of the well and to close the previously opened sleeve after the frac treatment, if desired, to isolate the newly stimulated zone to:
o prevent cross flow from the newly frac'd stage to previous stimulated stages;
o allow the frac to "heal", minimizing proppant, such as sand, flow back into the well while permitting the frac to settle around the proppant and forming a flow channel therethrough;
o open and close selected sleeves - can be done in any sequence within the wellbore; from heel to toe, from toe to heel or at any sequence of stages as desired.
= ability to close sleeves during the life of the well to control unwanted production from a particular stage or stages. One such example is the prevention or minimizing of water production in a water flood operation.
o fields or plays undergoing water flood development typically include wells that are injectors and producers. Water flow through the reservoir can be determined by several industry existing methods, ie.
production logging, radioactive/chemical tracers etc.
Once the location of water flow is determined, an operator can selectively close
5 sleeves to minimize water production at a production well so as to maximize oil production.
= ability to incorporate a plurality of sleeves within casing in newly drilled wells wherein only sections of the sleeves are opened and stimulated at one time.
o such an operation maximizes production and drawdown of the hydrocarbons along the length of the well, particularly in long deviated or horizontal wells.
= that the sleeves provide full bore access to the well after treatment.
o full bore access prevents flow restrictions for production or for remedial work over access to the well.
= ability to pinpoint stimulation, such as fracturing, acid injection etc, with sleeves provides more controllable "placement" of the stimulation unlike the limited entry systems, such as plug and perf or open hole systems, such as open hole packers with ball drop activated sleeves.
As taught in US published patent application US 2015-0129197 to Kobold Services Inc., incorporated by reference herein in its entirety, BHA
are known which incorporate, from an uphole end to a downhole end, a first flow control assembly or selector valve that is axially and moveably coupled to a second intermediate packer assembly, which in turn is axially and moveably coupled to a third downhole anchor assembly. The third downhole anchor assembly may be further coupled to an end unit, such as that having a casing collar locator (CCL).
The casing collar may be a stacked beam collar locator, such as taught in US
= ability to incorporate a plurality of sleeves within casing in newly drilled wells wherein only sections of the sleeves are opened and stimulated at one time.
o such an operation maximizes production and drawdown of the hydrocarbons along the length of the well, particularly in long deviated or horizontal wells.
= that the sleeves provide full bore access to the well after treatment.
o full bore access prevents flow restrictions for production or for remedial work over access to the well.
= ability to pinpoint stimulation, such as fracturing, acid injection etc, with sleeves provides more controllable "placement" of the stimulation unlike the limited entry systems, such as plug and perf or open hole systems, such as open hole packers with ball drop activated sleeves.
As taught in US published patent application US 2015-0129197 to Kobold Services Inc., incorporated by reference herein in its entirety, BHA
are known which incorporate, from an uphole end to a downhole end, a first flow control assembly or selector valve that is axially and moveably coupled to a second intermediate packer assembly, which in turn is axially and moveably coupled to a third downhole anchor assembly. The third downhole anchor assembly may be further coupled to an end unit, such as that having a casing collar locator (CCL).
The casing collar may be a stacked beam collar locator, such as taught in US
6 62/120,261 to Kobold Services Inc., filed February 24, 2015, incorporated by reference herein in its entirety.
When the BHA is telescopically extended, the packer and associated slips are released and the bypass valve is open for fluid flow through the BHA.
When the BHA is telescopically collapsed, the packer and associated slips are set and the bypass valve is closed, such as when in place for delivering treatment fluid to the wellbore above the packer. In this case, both the bypass valve closes and a first treatment port in the first assembly is aligned with a second treatment port in the second assembly. The first treatment port is formed in the side wall of the mandrel. The second treatment port is formed in the side wall of the second assembly.
The flow control assembly is secured to a conveyance string of coiled tubing, at an uphole end thereof, and can further comprise a plurality of tool subs coupled one to another, including an emergency release sub, a fluid jetting assembly or jet sub having one or more nozzles, and a ball seat. The ball seat is an emergency fluid blocking sub should the selector valve fail open and the jet sub is required. If used, the ball would need to be reverse circulated out of the well before treatment fluids could be reintroduced. The tool subs are in fluid communication with each other and to the coiled tubing such that treatment fluid may be delivered from the surface via the coiled tubing to the jet sub.
Treatment fluid can be delivered through the nozzles, or to the balance of the first assembly, as described below.
When the BHA is telescopically extended, the packer and associated slips are released and the bypass valve is open for fluid flow through the BHA.
When the BHA is telescopically collapsed, the packer and associated slips are set and the bypass valve is closed, such as when in place for delivering treatment fluid to the wellbore above the packer. In this case, both the bypass valve closes and a first treatment port in the first assembly is aligned with a second treatment port in the second assembly. The first treatment port is formed in the side wall of the mandrel. The second treatment port is formed in the side wall of the second assembly.
The flow control assembly is secured to a conveyance string of coiled tubing, at an uphole end thereof, and can further comprise a plurality of tool subs coupled one to another, including an emergency release sub, a fluid jetting assembly or jet sub having one or more nozzles, and a ball seat. The ball seat is an emergency fluid blocking sub should the selector valve fail open and the jet sub is required. If used, the ball would need to be reverse circulated out of the well before treatment fluids could be reintroduced. The tool subs are in fluid communication with each other and to the coiled tubing such that treatment fluid may be delivered from the surface via the coiled tubing to the jet sub.
Treatment fluid can be delivered through the nozzles, or to the balance of the first assembly, as described below.
7 The balance of the first assembly, downhole of the fluid jetting assembly, is a tubular mandrel having a first bore for delivering treatment fluid to the second assembly. A downhole plug is fit to the mandrel as a bypass valve for alternately blocking and opening a passage in the second bore of the second assembly. The first assembly's plug seals to a valve seat in the second bore of the second tubular sleeve of the second assembly as it moves therealong. The bypass valve plug alternately seals the second bore downhole of the second treatment port.
Fluid from the first assembly is controlled through the selector valve formed between the mandrel of the first assembly and a second tubular sleeve of the second assembly. The second tubular sleeve comprises a downhole bypass portion and an uphole treatment portion. The tubular mandrel of the first assembly comprises the first treatment port uphole of the plug for opening the first bore to an annulus between the tubular mandrel and the second assembly. The treatment portion of the second assembly comprises an intact uphole tubular portion, used to block the first fluid port to close the selector valve and a ported downhole portion having the second fluid port for opening the selector valve.
When the first assembly and tubular mandrel are in an uphole position relative to the second assembly the first fluid port of the first assembly moves uphole into the intact tubular portion, the side wall of the second tubular sleeve blocking the first treatment port of the first assembly within the second assembly and preventing treatment fluid from accessing the tool annulus. Further, as the first treatment port is shifted uphole to a blocked position uphole of the second treatment port, the plug is also displaced uphole, opening the bypass valve and establishing
Fluid from the first assembly is controlled through the selector valve formed between the mandrel of the first assembly and a second tubular sleeve of the second assembly. The second tubular sleeve comprises a downhole bypass portion and an uphole treatment portion. The tubular mandrel of the first assembly comprises the first treatment port uphole of the plug for opening the first bore to an annulus between the tubular mandrel and the second assembly. The treatment portion of the second assembly comprises an intact uphole tubular portion, used to block the first fluid port to close the selector valve and a ported downhole portion having the second fluid port for opening the selector valve.
When the first assembly and tubular mandrel are in an uphole position relative to the second assembly the first fluid port of the first assembly moves uphole into the intact tubular portion, the side wall of the second tubular sleeve blocking the first treatment port of the first assembly within the second assembly and preventing treatment fluid from accessing the tool annulus. Further, as the first treatment port is shifted uphole to a blocked position uphole of the second treatment port, the plug is also displaced uphole, opening the bypass valve and establishing
8 an equalization fluid flow path between the tool annulus and the BHA along the second bore and downhole of the packer.
Accordingly, with the selector valve closed, fluid delivered downhole can flow through the jet sub for perforation of the completion string thereabout. This is typically employed if there are no sliding sleeves or if a sleeve has failed closed.
The bypass valve is open for fluid communication of the tool annulus uphole of the BHA and the second and third assemblies and the wellbore downhole of the BHA.
When the first assembly and tubular mandrel are in a downhole position relative to the second assembly, the plug engages the valve seat of the second bore, closing the bypass valve. The first treatment port of the first assembly also moves downhole to align with the second treatment port, opening the selector valve for enabling treatment fluid to flow from the tubular mandrel's first bore to the tool annulus and vice versa. The tool annulus uphole of the BHA is isolated from the second and third assemblies and the wellbore downhole of the BHA.
With the selector valve open, fluid delivered downhole through the conveyance string can flow through the treatment fluid ports to access the tool annulus and open ports in a ported sleeve sub, is so positioned.
Alternatively, or used in sequence, flushing fluid can be provided either down the conveyance string and up the tool annulus, or down the annulus and up the conveyance string.
The BHA is positioned in a completion string having one or more ported sleeve subs. The resettable packer is in run-in mode and the packer is not set to engage sleeve. Sleeve ports of the ported sleeve sub remain closed. The packer is set to engage the sleeve and the BHA is shifted downhole to open the
Accordingly, with the selector valve closed, fluid delivered downhole can flow through the jet sub for perforation of the completion string thereabout. This is typically employed if there are no sliding sleeves or if a sleeve has failed closed.
The bypass valve is open for fluid communication of the tool annulus uphole of the BHA and the second and third assemblies and the wellbore downhole of the BHA.
When the first assembly and tubular mandrel are in a downhole position relative to the second assembly, the plug engages the valve seat of the second bore, closing the bypass valve. The first treatment port of the first assembly also moves downhole to align with the second treatment port, opening the selector valve for enabling treatment fluid to flow from the tubular mandrel's first bore to the tool annulus and vice versa. The tool annulus uphole of the BHA is isolated from the second and third assemblies and the wellbore downhole of the BHA.
With the selector valve open, fluid delivered downhole through the conveyance string can flow through the treatment fluid ports to access the tool annulus and open ports in a ported sleeve sub, is so positioned.
Alternatively, or used in sequence, flushing fluid can be provided either down the conveyance string and up the tool annulus, or down the annulus and up the conveyance string.
The BHA is positioned in a completion string having one or more ported sleeve subs. The resettable packer is in run-in mode and the packer is not set to engage sleeve. Sleeve ports of the ported sleeve sub remain closed. The packer is set to engage the sleeve and the BHA is shifted downhole to open the
9 ported sleeve sub. The selector valve is open with first and second fluid ports aligned for fluid flow to the tool annulus and through sleeve ports to the wellbore.
With the bypass valve open, the selector valve is closed and fluid can move freely between the tool annulus and the second bore.
Fluid in the conveyance string in the first bore is blocked from exiting or entering at the fluid ports.
With the bypass valve closed, with the plug engaged at the valve seal of the second bore, the selector valve is open and fluid moves freely between the tool annulus and the first bore. Fluid in the conveyance string can flow through the first bore, can flow through fluid ports into the tool annulus and through the ported sleeve sub ports to the wellbore thereout.
Unlike the BHA taught in US published application 2015-0129197, embodiments taught herein comprise a shifting tool incorporated therein which has opposing slips to selectively open and close sleeves in casing in a wellbore.
Figures #1A ¨ 1D
With reference to Figs. 1A to 1D, an embodiment of a coil tubing deployed bottomhole assembly (BHA) having opposing slips incorporated therein is shown in a run-in-hole (RIH) position. The BHA is simplified compared to prior art tools, has greater functionality and is capable of well flow control. The BHA
comprises at least the following components:
= a selector valve to control flow. The selector valve is independent of a shifting tool in the BHA used for manipulation of each of the sleeves. Thus, the selector valve may be available in a variety of configurations;
= the shifting tool comprising the upper and lower slip assemblies. The upper slip assembly is used to set the BHA and shift the sleeve downhole and open. The lower slip assembly, spaced from the upper slip assembly, is used to set the BHA and selectively close the sleeve uphole, as desired.
= a stacked beam locator, such as taught in US patent application 62/120,261, incorporated herein by reference in its entirety, for positioning the tool in the wellbore by locating, at a separate location, a collar positioned below the sleeve, unlike the prior art, such as taught in Canadian patent 2,693,676 to NCS Oilfield Services Canada Inc.
o locating, using an independent collar locator in the BHA to locate a collar below the sleeve, allows the implementation of a more positive, stacked beam locator, as the beam locator does not compete with other components in the BHA for radial space within the BHA. The stacked beam locator greatly improves consistent location of the sleeve with more discernable surface indication than other beam locators in the industry.
= this tool configuration uses stacked beam configuration as a location device;
= the stacked beam location system also provides much more side load resistance to the wall of the casing creating more drag in the well, creating more crisp, positive J-slot functionality and overall tool performance with respect to opening closing bypass valves and selector valves.
The stacked beam locator used in embodiments taught herein is thus distinguished over the prior art locator described above. The prior art locator is restricted to operate in the restricted diameter of the sleeve sub while maintaining the largest flow-through bore possible which also limits the radial engaging-load, reduces feedback and increases the risk of failure of sleeve detection.
= a J-slot mechanism for controlling engagement of the upper and lower slip assemblies. An example of a J-slot sequence is illustrated in Fig. 6;
o other sequences may be used - for example, a closing sequence may be omitted if, in a particular application, the oil company does not want to close the sleeves after the frac, but instead may only wish to close the sleeves at a date late in the life of the well.
o lower slips can be engaged on an opposing engagement cone to allow force upwards on the inner sleeve to close the sleeve, either right after the frac has been completed, at some later time during the same trip or at a later time during the life of the well on a separate trip.
o a J slot sequencing may be set up in a scenario of patterns for example:
i. the sequence could designed so as when the coiled tubing is pulled out of hole (POOH) after the frac, the tool leaves the sleeve open and pulls straight out of hole; or ii. the sequence could designed so as when the tool is POOH, the tool engages the open sleeve to close it, iii. other sequencing as desired; and = an activation sub or multiple functioning sub to remove an hydraulic volume of fluid which acts as an impediment to moving the tool so as to permit sleeves to open repeatedly in a well where all other sleeves are closed.
o shifting a tool string in a closed well creates such a hydraulic lock wherein the shifting tool/string cannot move unless the hydraulic volume of the fluid is allowed to travel somewhere so the tool/string can move, such as repeatedly using an activation sub.
Tool Operation As shown in Figs. 1A to 1D, when the BHA is RIH, the upper and lower slips of the shifting tool are retracted, as controlled by the "J" slot sequence, an example of which is shown in Fig. 6.
With the upper and lower slips retracted, the stacked locator in the BHA minimally engages the sleeves while travelling into the well, however because of a shallow engagement angle on the locator, the sleeves are not actuated and there is no discernable indication at surface. The stacked beam system maintains a friction force with an outer mandrel of the BHA at a sufficient load to keep the "J"
slot from functioning to the next position, in vertical or horizontal holes, preventing premature setting of the BHA in the sleeves or the casing.
Depending on the configuration of the selector valve, as the BHA is deployed, fluid may be circulated down the coiled tubing and returned up the annulus or, alternatively, fluid can be forced into the formation ahead of the BHA if a toe sub is utilized and is open. In embodiments, fluid is returned to surface up the annulus during deployment of the BHA.
Figures 2A ¨ 2D - Locating the BHA while pulling-out-of-hole (POOH) in casing Sleeves can be activated in any sequence in the wellbore, from heel to toe, toe to heel or, alternatively, in any sequence, as desired. When the BHA has been deployed to a desired depth during RIH, the BHA is cycled according to the J-slot sequence from the "RIH" position to a "Pull to Locate" position, as illustrated in Fig. 6.
As the coiled tubing and BHA is pulled to POOH, an inner mandrel of the BHA transitions uphole, as permitted by the J-slot, while the outer mandrel or housing of the BHA is held in position in the casing by the stacked locator.
The stacked locator provides sufficient force for the inner mandrel to travel uphole until indexing pins in the J-slot mechanism seat in J-slot guides. In both the "LOCATE"
mode and the "POOH" mode, the indexing pins support the tensile load, including the location force when the stacked beam locator locates in the locator collar. The location force at surface, determined by the spring strength of the stacked beam locator, is generally set at about 3,000 to about 5,000 daN over string load, so as to be a discernable, detectable load difference at surface. When the locator has located the sleeve, the POOH is stopped as the BHA is positioned at the desired sleeve and can be set in the casing.
To move the BHA, when the stacked beam locator is engaged in the locator collar, sufficient force is applied to the coiled tubing and the indexing pins on the "J" slot mechanism must support the release in order to pull the stacked beam locator out of and through the locator collar for moving the BHA to another position in the casing.
Figures 3A ¨ 3D ¨ Setting BHA in sleeve As above, when located, and therefore when RIH to the desired location, the stacked beam locator engaged in the locating collar holds the outer housing of the BHA in position in the casing while the inner mandrel is caused to slide downhole according to the "J" mechanism sequence, as shown in Fig. 6.
When the inner mandrel slides downhole, the packer element is driven downhole to engage an upper cone which then engages the upper slips, driving the upper slips outward into locking engagement in the inner sleeve. Further, the selector valve is shifted to a "FRAC" mode and a bypass valve to the BHA
downhole of the selector valve, is closed.
Figures 4A ¨40 ¨ Shifting sleeve open and fracturing With the upper slips of the shifting tool engaged in the casing, the packer element compressed and the bypass valve closed, if required, the sleeve can be shifted down to open, using coiled tubing force from surface and/or fluid pressure applied from above the tool.
When the upper slips are set in the casing, downward force compresses the packer element for isolating the wellbore therebelow and to drive the upper slips further into engagement in the inner sleeve. At a design force, shear screws, which hold the sleeve in the closed position during RIH operations, fail, allowing the inner sleeve to travel downhole for opening frac ports thereabove. The shear screw release load in the sleeve is adjustable by adding or subtracting the number of shear screws, adjusting the strength of the shear screws, or both.
Shifting of tools using force applied to coiled tubing, with or without additional hydraulic actuation, is well understood in prior art shifting tools for shifting sleeves. A few of the myriad references to use of shifting tools are provided herein by way of example only and are not intended to provide a complete listing of such prior art references.
Some examples of prior art shifting tools are well described in the background of US Patent 6,631,768 to Patel. Generally, it is well known to use a shifting tool to allow a force, applied to the shifting tool, to be applied to a downhole tool such as a sleeve, thereby providing the necessary force to actuate or shift the sleeve.
US 5,355,953 to Shy et al. teaches that it is well known to use shifter tools which removeably carry key sets thereon for engaging in a series of longitudinally spaced series of annular, transverse notches on the interior side surfaces of sleeves for shifting the sleeve in horizontal wellbores. The sleeves are shifted open and/or closed using such tools through axial movement of engaged shifter keys toward and away from the anchor keys.
US 5,305,833 to Collins teaches using shifting tools which have locating dogs for selectively locating and engaging a shoulder inside a sleeve valve.
The sleeve valve is pressurized for moving between an opened and closed position.
Primary keys engage and selectively shift the sleeve to an intermediate equalizing position. Secondary keys lead the primary keys in the shifting direction and engage the sleeve to move to a fully open detent position.
US 5,636,694 to Mireles et al teaches use of hydraulic pressure to stroke a sleeve. The sleeves are shifted while running a running tool on coiled tubing. The shifting tool is anchored to the body of the sleeve for proper orientation in the sleeve. The shifting tool is resettable when the hydraulic pressure is withdrawn.
US Patents 5,183,114 and 5,211,241 to Mashaw et al teach a sleeve which is moveable between open, intermediate and closed positions. A pressure operated shifting tool, lowered into the sleeve, such as on reeled tubing, selectively locates in the sleeve, engages the sleeve and moves the sleeve upwardly or downwardly as required.
US Patent 5,381,862 to Szarka et al teaches a coiled tubing operated, full opening, completion tool system which utilizes a positioner tool for hydraulically opening and closing sliding sleeves in casing valves.
US Patent 4,917,191 to Hopmann et al teaches use of retracted, selectively expandable shifting means which are mechanically manipulated to locate and engage within a sliding sleeve. Thereafter, hydraulic means, such as a piston, are activated to drive the sleeve in opening or a closing directions.
Such prior art which relies generally upon engagement of a mechanism such as a collet, dog or other protruding member into a profile on the inner surface of the sleeve is in contrast to embodiments taught in CA
2,738,907 to NCS Oilfield Services Canada Inc., which engages a packer element or anchoring assembly thereof within a smooth, featureless inner surface of the sleeve and thereafter, applies pressure above the element to apply force to the sleeve to shift the sleeve open.
As described above, Applicant has designed a sleeve where the initial shift of the sleeve is controlled by shear screws with a predetermined sheer strength. Once the shear value of the screws, determined such as by adjusting the number of screws to achieve specific operating parameters, is overcome, the inner sleeve is allowed to travel down. Movement of the sleeve may be dampened to control the acceleration of the internal sleeve and the shock load when the sleeve reaches its shoulder end travel position, such as taught in US published application 2015-0013991 to Kobold Services Inc., of Calgary, Alberta, Canada, incorporated herein by reference in its entirety. By minimizing the shock load, tool longevity is greatly increased and fluid hammer shock load to the open formation is managed so as not to exceed the fracture breakdown pressure of the formation.
Opening of the sleeve is indicated at surface by a sudden reduction in coiled tubing string weight. The ability to determine whether the sleeve is open or not is important in the event an operator must troubleshoot problems, for example breaking down the formation, as it eliminates any concern of sleeve malfunction.
Controlled opening load and closing load of the sleeve, after the initial opening of the sleeve, is aided by a detent assembly on one or both of upper and lower ends of the inner sleeve. The detent assembly may be adjusted to actuate at loads from about 5,000 to about 10,000 daN, by way of example. The detent load is independent of the initial shear screw load to open the sleeve for the first time.
Independence provides additional safety against premature opening of the sleeves during casing/liner installation and cementing operations.
Moving the BHA downhole within the wellbore requires relieving hydraulic compression, which is created in the casing below the BHA, if sleeves or ports therebelow are not open to formation. In embodiments, a multi-set activation sub is used to allow fluid to be displaced or travel somewhere while the BHA
is shifted. Once the BHA is released from the casing after fracturing a zone, the activation sub is reset so that the BHA can be relocated and another sleeve shifted.
If a port is open in the wellbore below the BHA, the activation sub may be eliminated as a pathway for displacement of fluid therebelow is provided by the port.
Abrasa-jetting capability with or without the dropping of balls from surface In the event a sleeve does not function properly or a sleeve does function or the reservoir refuses to break down thereat, the BHA may be located and set at another location in the casing other than at a sleeve, so as to abrasa-jet cut an opening in the casing as a backup procedure to gain access to the reservoir.
The unique feature of engaging the slips anywhere in the casing, and not just in the sleeves, provides an option to set the BHA in the casing to allow for random pressure testing and/or fracturing of the formation at a location other than at a sleeve. In embodiments, the use of balls or manually actuated valves located above the frac ports in the BHA, allows fluid flow to be diverted from the frac flow to an abrasa-jet cutting head above the frac ports that can be used to cut perforations in the casing. The mandrel and attached jet cutting head can be shifted downhole to place the jets close to the sleeves and the slips set in the casing. Thus, the replacements perforations can be in close proximity to the failed sleeve ports.
Setting the BHA in casing also provides the ability to isolate pre-perforated perforations with an isolation configuration of the BHA or to abrasa-jet cut all the perforations in a new wellbore, thereby not using sleeves at all.
The BHA may also be utilized in a hybrid wellbore configuration where there are a combination of abrasa jet cuts and sleeves, or pre-perforated areas and sleeves or pre-perforated areas and abrasa-jet perforations.
The BHA may be configured with a spring retention packer element in combination with a bypass valve, or may be configured using a tension packer element, with or without the bypass, as taught in US provisional application 62/110,994 filed February 2, 2015 by Applicant, incorporated herein by reference in its entirety. Advantageously, the tension element is designed to pull away more efficiently from the casing under hydraulic pressure after a frac than a spring retention element. Thus, Applicant believes the tension element provides a means to eliminate the bypass valve, typically a sliding member, thus simplifying the overall BHA. Instead of relaying fluid through a bypass valve, fluid can bypass the tension element.
Figures 5A ¨ 50 ¨ Close sleeve (5,000 to 10,000 daN) Upon completion of the frac, the sleeve may be closed or left open.
In the case where the sleeve is to be closed, according to embodiments taught herein, the coiled tubing is POOH. The inner mandrel of the BHA, as it begins to move out-of-hole, opens a bypass around the BHA and expands the selector valve to close and isolate the coiled tubing bore from the wellbore. The pressure across the tool is equalized and debris is flushed from around the BHA. The outer housing of the BHA is held in place by the stacked locator and the inner mandrel transitions uphole, releasing the packer element and top slips. The mandrel lifts the lower cone to engage the lower slips. When the lower slips grip the sleeve, the BHA pulls the inner sleeve closed, closing the frac ports. The detents in the frac sleeve are adjustable to establish a suitable release loading as described above. An example of a suitable release loading is 5,000 to
With the bypass valve open, the selector valve is closed and fluid can move freely between the tool annulus and the second bore.
Fluid in the conveyance string in the first bore is blocked from exiting or entering at the fluid ports.
With the bypass valve closed, with the plug engaged at the valve seal of the second bore, the selector valve is open and fluid moves freely between the tool annulus and the first bore. Fluid in the conveyance string can flow through the first bore, can flow through fluid ports into the tool annulus and through the ported sleeve sub ports to the wellbore thereout.
Unlike the BHA taught in US published application 2015-0129197, embodiments taught herein comprise a shifting tool incorporated therein which has opposing slips to selectively open and close sleeves in casing in a wellbore.
Figures #1A ¨ 1D
With reference to Figs. 1A to 1D, an embodiment of a coil tubing deployed bottomhole assembly (BHA) having opposing slips incorporated therein is shown in a run-in-hole (RIH) position. The BHA is simplified compared to prior art tools, has greater functionality and is capable of well flow control. The BHA
comprises at least the following components:
= a selector valve to control flow. The selector valve is independent of a shifting tool in the BHA used for manipulation of each of the sleeves. Thus, the selector valve may be available in a variety of configurations;
= the shifting tool comprising the upper and lower slip assemblies. The upper slip assembly is used to set the BHA and shift the sleeve downhole and open. The lower slip assembly, spaced from the upper slip assembly, is used to set the BHA and selectively close the sleeve uphole, as desired.
= a stacked beam locator, such as taught in US patent application 62/120,261, incorporated herein by reference in its entirety, for positioning the tool in the wellbore by locating, at a separate location, a collar positioned below the sleeve, unlike the prior art, such as taught in Canadian patent 2,693,676 to NCS Oilfield Services Canada Inc.
o locating, using an independent collar locator in the BHA to locate a collar below the sleeve, allows the implementation of a more positive, stacked beam locator, as the beam locator does not compete with other components in the BHA for radial space within the BHA. The stacked beam locator greatly improves consistent location of the sleeve with more discernable surface indication than other beam locators in the industry.
= this tool configuration uses stacked beam configuration as a location device;
= the stacked beam location system also provides much more side load resistance to the wall of the casing creating more drag in the well, creating more crisp, positive J-slot functionality and overall tool performance with respect to opening closing bypass valves and selector valves.
The stacked beam locator used in embodiments taught herein is thus distinguished over the prior art locator described above. The prior art locator is restricted to operate in the restricted diameter of the sleeve sub while maintaining the largest flow-through bore possible which also limits the radial engaging-load, reduces feedback and increases the risk of failure of sleeve detection.
= a J-slot mechanism for controlling engagement of the upper and lower slip assemblies. An example of a J-slot sequence is illustrated in Fig. 6;
o other sequences may be used - for example, a closing sequence may be omitted if, in a particular application, the oil company does not want to close the sleeves after the frac, but instead may only wish to close the sleeves at a date late in the life of the well.
o lower slips can be engaged on an opposing engagement cone to allow force upwards on the inner sleeve to close the sleeve, either right after the frac has been completed, at some later time during the same trip or at a later time during the life of the well on a separate trip.
o a J slot sequencing may be set up in a scenario of patterns for example:
i. the sequence could designed so as when the coiled tubing is pulled out of hole (POOH) after the frac, the tool leaves the sleeve open and pulls straight out of hole; or ii. the sequence could designed so as when the tool is POOH, the tool engages the open sleeve to close it, iii. other sequencing as desired; and = an activation sub or multiple functioning sub to remove an hydraulic volume of fluid which acts as an impediment to moving the tool so as to permit sleeves to open repeatedly in a well where all other sleeves are closed.
o shifting a tool string in a closed well creates such a hydraulic lock wherein the shifting tool/string cannot move unless the hydraulic volume of the fluid is allowed to travel somewhere so the tool/string can move, such as repeatedly using an activation sub.
Tool Operation As shown in Figs. 1A to 1D, when the BHA is RIH, the upper and lower slips of the shifting tool are retracted, as controlled by the "J" slot sequence, an example of which is shown in Fig. 6.
With the upper and lower slips retracted, the stacked locator in the BHA minimally engages the sleeves while travelling into the well, however because of a shallow engagement angle on the locator, the sleeves are not actuated and there is no discernable indication at surface. The stacked beam system maintains a friction force with an outer mandrel of the BHA at a sufficient load to keep the "J"
slot from functioning to the next position, in vertical or horizontal holes, preventing premature setting of the BHA in the sleeves or the casing.
Depending on the configuration of the selector valve, as the BHA is deployed, fluid may be circulated down the coiled tubing and returned up the annulus or, alternatively, fluid can be forced into the formation ahead of the BHA if a toe sub is utilized and is open. In embodiments, fluid is returned to surface up the annulus during deployment of the BHA.
Figures 2A ¨ 2D - Locating the BHA while pulling-out-of-hole (POOH) in casing Sleeves can be activated in any sequence in the wellbore, from heel to toe, toe to heel or, alternatively, in any sequence, as desired. When the BHA has been deployed to a desired depth during RIH, the BHA is cycled according to the J-slot sequence from the "RIH" position to a "Pull to Locate" position, as illustrated in Fig. 6.
As the coiled tubing and BHA is pulled to POOH, an inner mandrel of the BHA transitions uphole, as permitted by the J-slot, while the outer mandrel or housing of the BHA is held in position in the casing by the stacked locator.
The stacked locator provides sufficient force for the inner mandrel to travel uphole until indexing pins in the J-slot mechanism seat in J-slot guides. In both the "LOCATE"
mode and the "POOH" mode, the indexing pins support the tensile load, including the location force when the stacked beam locator locates in the locator collar. The location force at surface, determined by the spring strength of the stacked beam locator, is generally set at about 3,000 to about 5,000 daN over string load, so as to be a discernable, detectable load difference at surface. When the locator has located the sleeve, the POOH is stopped as the BHA is positioned at the desired sleeve and can be set in the casing.
To move the BHA, when the stacked beam locator is engaged in the locator collar, sufficient force is applied to the coiled tubing and the indexing pins on the "J" slot mechanism must support the release in order to pull the stacked beam locator out of and through the locator collar for moving the BHA to another position in the casing.
Figures 3A ¨ 3D ¨ Setting BHA in sleeve As above, when located, and therefore when RIH to the desired location, the stacked beam locator engaged in the locating collar holds the outer housing of the BHA in position in the casing while the inner mandrel is caused to slide downhole according to the "J" mechanism sequence, as shown in Fig. 6.
When the inner mandrel slides downhole, the packer element is driven downhole to engage an upper cone which then engages the upper slips, driving the upper slips outward into locking engagement in the inner sleeve. Further, the selector valve is shifted to a "FRAC" mode and a bypass valve to the BHA
downhole of the selector valve, is closed.
Figures 4A ¨40 ¨ Shifting sleeve open and fracturing With the upper slips of the shifting tool engaged in the casing, the packer element compressed and the bypass valve closed, if required, the sleeve can be shifted down to open, using coiled tubing force from surface and/or fluid pressure applied from above the tool.
When the upper slips are set in the casing, downward force compresses the packer element for isolating the wellbore therebelow and to drive the upper slips further into engagement in the inner sleeve. At a design force, shear screws, which hold the sleeve in the closed position during RIH operations, fail, allowing the inner sleeve to travel downhole for opening frac ports thereabove. The shear screw release load in the sleeve is adjustable by adding or subtracting the number of shear screws, adjusting the strength of the shear screws, or both.
Shifting of tools using force applied to coiled tubing, with or without additional hydraulic actuation, is well understood in prior art shifting tools for shifting sleeves. A few of the myriad references to use of shifting tools are provided herein by way of example only and are not intended to provide a complete listing of such prior art references.
Some examples of prior art shifting tools are well described in the background of US Patent 6,631,768 to Patel. Generally, it is well known to use a shifting tool to allow a force, applied to the shifting tool, to be applied to a downhole tool such as a sleeve, thereby providing the necessary force to actuate or shift the sleeve.
US 5,355,953 to Shy et al. teaches that it is well known to use shifter tools which removeably carry key sets thereon for engaging in a series of longitudinally spaced series of annular, transverse notches on the interior side surfaces of sleeves for shifting the sleeve in horizontal wellbores. The sleeves are shifted open and/or closed using such tools through axial movement of engaged shifter keys toward and away from the anchor keys.
US 5,305,833 to Collins teaches using shifting tools which have locating dogs for selectively locating and engaging a shoulder inside a sleeve valve.
The sleeve valve is pressurized for moving between an opened and closed position.
Primary keys engage and selectively shift the sleeve to an intermediate equalizing position. Secondary keys lead the primary keys in the shifting direction and engage the sleeve to move to a fully open detent position.
US 5,636,694 to Mireles et al teaches use of hydraulic pressure to stroke a sleeve. The sleeves are shifted while running a running tool on coiled tubing. The shifting tool is anchored to the body of the sleeve for proper orientation in the sleeve. The shifting tool is resettable when the hydraulic pressure is withdrawn.
US Patents 5,183,114 and 5,211,241 to Mashaw et al teach a sleeve which is moveable between open, intermediate and closed positions. A pressure operated shifting tool, lowered into the sleeve, such as on reeled tubing, selectively locates in the sleeve, engages the sleeve and moves the sleeve upwardly or downwardly as required.
US Patent 5,381,862 to Szarka et al teaches a coiled tubing operated, full opening, completion tool system which utilizes a positioner tool for hydraulically opening and closing sliding sleeves in casing valves.
US Patent 4,917,191 to Hopmann et al teaches use of retracted, selectively expandable shifting means which are mechanically manipulated to locate and engage within a sliding sleeve. Thereafter, hydraulic means, such as a piston, are activated to drive the sleeve in opening or a closing directions.
Such prior art which relies generally upon engagement of a mechanism such as a collet, dog or other protruding member into a profile on the inner surface of the sleeve is in contrast to embodiments taught in CA
2,738,907 to NCS Oilfield Services Canada Inc., which engages a packer element or anchoring assembly thereof within a smooth, featureless inner surface of the sleeve and thereafter, applies pressure above the element to apply force to the sleeve to shift the sleeve open.
As described above, Applicant has designed a sleeve where the initial shift of the sleeve is controlled by shear screws with a predetermined sheer strength. Once the shear value of the screws, determined such as by adjusting the number of screws to achieve specific operating parameters, is overcome, the inner sleeve is allowed to travel down. Movement of the sleeve may be dampened to control the acceleration of the internal sleeve and the shock load when the sleeve reaches its shoulder end travel position, such as taught in US published application 2015-0013991 to Kobold Services Inc., of Calgary, Alberta, Canada, incorporated herein by reference in its entirety. By minimizing the shock load, tool longevity is greatly increased and fluid hammer shock load to the open formation is managed so as not to exceed the fracture breakdown pressure of the formation.
Opening of the sleeve is indicated at surface by a sudden reduction in coiled tubing string weight. The ability to determine whether the sleeve is open or not is important in the event an operator must troubleshoot problems, for example breaking down the formation, as it eliminates any concern of sleeve malfunction.
Controlled opening load and closing load of the sleeve, after the initial opening of the sleeve, is aided by a detent assembly on one or both of upper and lower ends of the inner sleeve. The detent assembly may be adjusted to actuate at loads from about 5,000 to about 10,000 daN, by way of example. The detent load is independent of the initial shear screw load to open the sleeve for the first time.
Independence provides additional safety against premature opening of the sleeves during casing/liner installation and cementing operations.
Moving the BHA downhole within the wellbore requires relieving hydraulic compression, which is created in the casing below the BHA, if sleeves or ports therebelow are not open to formation. In embodiments, a multi-set activation sub is used to allow fluid to be displaced or travel somewhere while the BHA
is shifted. Once the BHA is released from the casing after fracturing a zone, the activation sub is reset so that the BHA can be relocated and another sleeve shifted.
If a port is open in the wellbore below the BHA, the activation sub may be eliminated as a pathway for displacement of fluid therebelow is provided by the port.
Abrasa-jetting capability with or without the dropping of balls from surface In the event a sleeve does not function properly or a sleeve does function or the reservoir refuses to break down thereat, the BHA may be located and set at another location in the casing other than at a sleeve, so as to abrasa-jet cut an opening in the casing as a backup procedure to gain access to the reservoir.
The unique feature of engaging the slips anywhere in the casing, and not just in the sleeves, provides an option to set the BHA in the casing to allow for random pressure testing and/or fracturing of the formation at a location other than at a sleeve. In embodiments, the use of balls or manually actuated valves located above the frac ports in the BHA, allows fluid flow to be diverted from the frac flow to an abrasa-jet cutting head above the frac ports that can be used to cut perforations in the casing. The mandrel and attached jet cutting head can be shifted downhole to place the jets close to the sleeves and the slips set in the casing. Thus, the replacements perforations can be in close proximity to the failed sleeve ports.
Setting the BHA in casing also provides the ability to isolate pre-perforated perforations with an isolation configuration of the BHA or to abrasa-jet cut all the perforations in a new wellbore, thereby not using sleeves at all.
The BHA may also be utilized in a hybrid wellbore configuration where there are a combination of abrasa jet cuts and sleeves, or pre-perforated areas and sleeves or pre-perforated areas and abrasa-jet perforations.
The BHA may be configured with a spring retention packer element in combination with a bypass valve, or may be configured using a tension packer element, with or without the bypass, as taught in US provisional application 62/110,994 filed February 2, 2015 by Applicant, incorporated herein by reference in its entirety. Advantageously, the tension element is designed to pull away more efficiently from the casing under hydraulic pressure after a frac than a spring retention element. Thus, Applicant believes the tension element provides a means to eliminate the bypass valve, typically a sliding member, thus simplifying the overall BHA. Instead of relaying fluid through a bypass valve, fluid can bypass the tension element.
Figures 5A ¨ 50 ¨ Close sleeve (5,000 to 10,000 daN) Upon completion of the frac, the sleeve may be closed or left open.
In the case where the sleeve is to be closed, according to embodiments taught herein, the coiled tubing is POOH. The inner mandrel of the BHA, as it begins to move out-of-hole, opens a bypass around the BHA and expands the selector valve to close and isolate the coiled tubing bore from the wellbore. The pressure across the tool is equalized and debris is flushed from around the BHA. The outer housing of the BHA is held in place by the stacked locator and the inner mandrel transitions uphole, releasing the packer element and top slips. The mandrel lifts the lower cone to engage the lower slips. When the lower slips grip the sleeve, the BHA pulls the inner sleeve closed, closing the frac ports. The detents in the frac sleeve are adjustable to establish a suitable release loading as described above. An example of a suitable release loading is 5,000 to
10,000 daN over string weight at surface. When the sleeve is shifted to close there is a sudden loss of weight providing a positive indication at surface, indicating the closing of the sleeve.
Sleeves may be closed right after the frac for a variety of reasons, including but not limited to:
= isolating the frac treatment in the reservoir by preventing the treatment fluid from flowing back into the wellbore. By isolating the frac treatment, the formation may be allowed to heal so as to contain the frac sand therein. Retaining the sand in the fracture reduces sand production from the well, as well as the cost of recovery of the sand from the produced fluids;
= isolating the frac treatment fluid from previously fractured stages/sleeves to prevent cross flow in the well;
= minimizing the amount of clean fluid required to clean the BHA
components travelling to the next stage As desired, the closed sleeves may be re-opened at any time. For example, in the case where the well has been frac'd from the toe to the heel, once the last sleeve at the heel is closed, the coiled tubing deployed BHA can be moved back to the toe and the process of locating and opening all the sleeves can be performed from the toe back to the heel as the BHA is POOH.
Optionally, the sleeves can be opened days, weeks, months or longer after the sleeves were closed. Generally, these time periods are all reservoir and area specific.
As noted above, the sleeve has detents used during opening and closing of the sleeve. The detents in this example are set to release at 5,000 to 10,000 daN. When the CT is pulled uphole, the upward force on the slips and sleeve enters the range at which the detent releases and the sleeve moves uphole from the open position, shown in Figs. 7A - 7C, to the closed position, shown in Figs. 8A - 8C. When the sleeve moves from the open to the closed position, the sleeve is also dampened as taught in US published application 2015-0013991.
The closing action is discernable at surface as a coiled tubing string weight loss.
When the sleeve is closed, the coiled tubing may be over-pulled, that is pulled greater than the upper limit of the detent release range, being greater than 10,000 daN for the example provided, to confirm the sleeve is closed, however in most cases over-pulling is not necessary. As one will readily appreciate, surface weight indication for the various operations including, but not limited to locating the sleeve, shifting it open and shifting it closed, is an important advantage of embodiments described herein with regards to operational confidence and optimizing operations at surface.
An alternate method to confirm a sleeve is closed is to reset the BHA
in the casing below the sleeve and to perform a pressure test to determine if the ports are closed by the sleeve.
Both in closing the sleeve and opening it, the "J" mechanism is designed in such a way that the indexing lugs in the "J" slot do not take the shifting load. The shifting load in these sequences is born by internal shoulders between the inner mandrel and outer housing. The indexing pins only take the drag load of the tool during RIH, POOH or locating the tool in the sleeve.
In embodiments, both the upper and the lower opposing slip assemblies are activated by cones, reversed to each other.
In order to POOH without closing the sleeve, the coiled tubing is pulled without exceeding the lower limit of the detent release range, 5,000 daN
pulling force over string weight in the example provided. If the force is not exceeded, the sleeve detent is not activated and the sleeve is not shifted.
Accordingly, no loss of weight is seen at surface which is indicative that the sleeve has not closed. With reference to Fig. 6, in the "J" sequence example shown, a closing feature or cycle is included, however it is not used during POOH when a sleeve is to be selectively left open. In the case of a wellbore where all the sleeves are to be left open after the frac, the "J" sequence can be modified to eliminate the closing cycle after the frac so as to come straight off the sleeve to POOH.
The descried J-slot can be predetermined before RIH and the BHA configured accordingly.
Regardless whether the sleeve is closed, or left open after the frac by POOH, the next function or cycle in the "J" sequence is to RIH, as shown in Fig. 1A, to release the tool and then repeat POOH as shown in Fig. 2A, to locate the next sleeve.
Fiq. 6 ¨ Example of a "J" Mechanism sequence The "J" mechanism sequence is adjustable in its pattern. In the example shown in Fig. 6, as previously described, the sequence has a mid position or cycle used to close the sleeve after the frac or at some later date. The mid position may be eliminated if no sleeves are to be closed after the stage is frac'd to save cycle time making the operation more efficient.
The "J" mechanism has a bearing assembly design to permit the inner mandrel and indexing pins to rotate. The bearing assembly has significant tension and compression capability to deal with the load on the indexing pins during RIH, POOH or locating the tool in the sleeve. The rotation also allows the inner mandrel to transition with little friction, making the transitions between various cycles of the tool more effective so the tool does not malfunction. For example, if the transition load between sequences is too high, the outer housing of the tool would skid because the stacked locator friction to the casing would be too high, creating operational problems in the well.
A variety of indexing pin combinations, using one, two, or more spaced indexing pins, may be used with corresponding "J" mechanism sequence patterns.
Another important feature of the "J" mechanism's bearing assembly design is that it does not require the outer housing of the tool to rotate, making transitions between cycles much easier, but also allowing the tool to cycle to the RIH mode from the POOH mode if the outer housing and tool cannot be POOH due to debris. Allowing the inner mandrel of the BHA to cycle to the RIH mode acts as a safety feature, permitting travel downhole to reset the BHA before having to POOH
the BHA thru debris.
Sleeves may be closed right after the frac for a variety of reasons, including but not limited to:
= isolating the frac treatment in the reservoir by preventing the treatment fluid from flowing back into the wellbore. By isolating the frac treatment, the formation may be allowed to heal so as to contain the frac sand therein. Retaining the sand in the fracture reduces sand production from the well, as well as the cost of recovery of the sand from the produced fluids;
= isolating the frac treatment fluid from previously fractured stages/sleeves to prevent cross flow in the well;
= minimizing the amount of clean fluid required to clean the BHA
components travelling to the next stage As desired, the closed sleeves may be re-opened at any time. For example, in the case where the well has been frac'd from the toe to the heel, once the last sleeve at the heel is closed, the coiled tubing deployed BHA can be moved back to the toe and the process of locating and opening all the sleeves can be performed from the toe back to the heel as the BHA is POOH.
Optionally, the sleeves can be opened days, weeks, months or longer after the sleeves were closed. Generally, these time periods are all reservoir and area specific.
As noted above, the sleeve has detents used during opening and closing of the sleeve. The detents in this example are set to release at 5,000 to 10,000 daN. When the CT is pulled uphole, the upward force on the slips and sleeve enters the range at which the detent releases and the sleeve moves uphole from the open position, shown in Figs. 7A - 7C, to the closed position, shown in Figs. 8A - 8C. When the sleeve moves from the open to the closed position, the sleeve is also dampened as taught in US published application 2015-0013991.
The closing action is discernable at surface as a coiled tubing string weight loss.
When the sleeve is closed, the coiled tubing may be over-pulled, that is pulled greater than the upper limit of the detent release range, being greater than 10,000 daN for the example provided, to confirm the sleeve is closed, however in most cases over-pulling is not necessary. As one will readily appreciate, surface weight indication for the various operations including, but not limited to locating the sleeve, shifting it open and shifting it closed, is an important advantage of embodiments described herein with regards to operational confidence and optimizing operations at surface.
An alternate method to confirm a sleeve is closed is to reset the BHA
in the casing below the sleeve and to perform a pressure test to determine if the ports are closed by the sleeve.
Both in closing the sleeve and opening it, the "J" mechanism is designed in such a way that the indexing lugs in the "J" slot do not take the shifting load. The shifting load in these sequences is born by internal shoulders between the inner mandrel and outer housing. The indexing pins only take the drag load of the tool during RIH, POOH or locating the tool in the sleeve.
In embodiments, both the upper and the lower opposing slip assemblies are activated by cones, reversed to each other.
In order to POOH without closing the sleeve, the coiled tubing is pulled without exceeding the lower limit of the detent release range, 5,000 daN
pulling force over string weight in the example provided. If the force is not exceeded, the sleeve detent is not activated and the sleeve is not shifted.
Accordingly, no loss of weight is seen at surface which is indicative that the sleeve has not closed. With reference to Fig. 6, in the "J" sequence example shown, a closing feature or cycle is included, however it is not used during POOH when a sleeve is to be selectively left open. In the case of a wellbore where all the sleeves are to be left open after the frac, the "J" sequence can be modified to eliminate the closing cycle after the frac so as to come straight off the sleeve to POOH.
The descried J-slot can be predetermined before RIH and the BHA configured accordingly.
Regardless whether the sleeve is closed, or left open after the frac by POOH, the next function or cycle in the "J" sequence is to RIH, as shown in Fig. 1A, to release the tool and then repeat POOH as shown in Fig. 2A, to locate the next sleeve.
Fiq. 6 ¨ Example of a "J" Mechanism sequence The "J" mechanism sequence is adjustable in its pattern. In the example shown in Fig. 6, as previously described, the sequence has a mid position or cycle used to close the sleeve after the frac or at some later date. The mid position may be eliminated if no sleeves are to be closed after the stage is frac'd to save cycle time making the operation more efficient.
The "J" mechanism has a bearing assembly design to permit the inner mandrel and indexing pins to rotate. The bearing assembly has significant tension and compression capability to deal with the load on the indexing pins during RIH, POOH or locating the tool in the sleeve. The rotation also allows the inner mandrel to transition with little friction, making the transitions between various cycles of the tool more effective so the tool does not malfunction. For example, if the transition load between sequences is too high, the outer housing of the tool would skid because the stacked locator friction to the casing would be too high, creating operational problems in the well.
A variety of indexing pin combinations, using one, two, or more spaced indexing pins, may be used with corresponding "J" mechanism sequence patterns.
Another important feature of the "J" mechanism's bearing assembly design is that it does not require the outer housing of the tool to rotate, making transitions between cycles much easier, but also allowing the tool to cycle to the RIH mode from the POOH mode if the outer housing and tool cannot be POOH due to debris. Allowing the inner mandrel of the BHA to cycle to the RIH mode acts as a safety feature, permitting travel downhole to reset the BHA before having to POOH
the BHA thru debris.
Claims
1. A downhole tool for shifting a sleeve comprising-a first slip assembly, a second slip assembly located downhole to the first slip assembly, and a J-slot mechanism, wherein said J-slot mechanism alternates actuation of the first and second slip assemblies for selectively opening and closing the sleeve.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2901074A CA2901074A1 (en) | 2015-08-20 | 2015-08-20 | Sleeve system for use in wellbore completion operations |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2901074A CA2901074A1 (en) | 2015-08-20 | 2015-08-20 | Sleeve system for use in wellbore completion operations |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2901074A1 true CA2901074A1 (en) | 2016-12-26 |
Family
ID=57590909
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2901074A Abandoned CA2901074A1 (en) | 2015-08-20 | 2015-08-20 | Sleeve system for use in wellbore completion operations |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA2901074A1 (en) |
Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US10683730B2 (en) | 2014-12-29 | 2020-06-16 | Ncs Multistage Inc. | Apparatus and method for treating a reservoir using re-closeable sleeves, and actuating the sleeves with bi-directional slips |
| US11454087B2 (en) | 2018-09-25 | 2022-09-27 | Advanced Upstream Ltd. | Delayed opening port assembly |
| US11939836B2 (en) | 2020-08-31 | 2024-03-26 | Advanced Upstream Ltd. | Port sub with delayed opening sequence |
-
2015
- 2015-08-20 CA CA2901074A patent/CA2901074A1/en not_active Abandoned
Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US10683730B2 (en) | 2014-12-29 | 2020-06-16 | Ncs Multistage Inc. | Apparatus and method for treating a reservoir using re-closeable sleeves, and actuating the sleeves with bi-directional slips |
| US11454087B2 (en) | 2018-09-25 | 2022-09-27 | Advanced Upstream Ltd. | Delayed opening port assembly |
| US11939836B2 (en) | 2020-08-31 | 2024-03-26 | Advanced Upstream Ltd. | Port sub with delayed opening sequence |
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Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| FZDE | Discontinued |
Effective date: 20180821 |