Rotatably-Actuated Fluid Treatment System Using Coiled Tubing

Abstract

A system for treating a formation of a borehole having casing has a sleeve, a motor, and a packer. The sleeve is disposed on the casing in the borehole and has a port communicating out of the sleeve. An insert disposed in the sleeve is movable in the sleeve from closed to opened position relative to the port. The motor is deployed in the casing with coiled tubing and is operable to impart rotation. The packer is operatively coupled to the motor. In response to the rotation imparted by the motor, the packer sets in the insert of the sleeve and moves the insert to the opened condition.

Description

BACKGROUND OF THE DISCLOSURE

With advancements in the industry, packers deployed with coiled tubing and used with sliding sleeves are becoming a preferred method of treating lateral wells. With that said, several techniques have been developed for treating zones of lateral well with these components.

Referring to FIG. 1, for example, a fracturing system 10 of the prior art uses coiled tubing 24, sliding sleeves 30A-C, a packer 40, and a shifting tool 45. Although shown as vertical, the borehole 12 can be, and most likely is, a horizontal or deviated borehole. A casing or liner 14 is cemented in the borehole 12 using standard procedures so cement 16 supports the casing 14 in the borehole 12. At suitable zones along the borehole 12, the sliding sleeves 30A-C are cemented in place along the casing 14 in closed conditions.

The system 10 is similar to a ZoneSelect coiled tubing (CT) system available from Weatherford International Ltd. The system 10 enables access to individual zones in the reservoir with the coiled-tubing-actuated sleeves 30A-C and with the packer 40 and shifting tool 45 on the single coiled-tubing bottomhole assembly (BHA). In the system 10, the sleeves 30A-C are actuated using the coiled tubing 24 and the shifting tool 45. The resettable coiled-tubing packer 40 is then set below the sleeve 30A-C, and the zone is stimulated while the coil remains in the well.

To begin a fracture operation, for example, operators deploy the packer 40 and shifting tool 45 on coiled tubing 24 down the casing 14. The shifting tool 45 is deployed inside an insert of the lower sliding sleeve 30A, and operators pull up on the tubing 24 to open the insert on the sleeve 30A to expose external ports.

Operators then run the packer 40 into the joint below the open sleeve 30A and set the packer 40 hydraulically. At this point, operators perform annular fracture operations by pumping fluid down the annulus between the casing 14 and the coiled tubing 24 so that the fracture fluid exits ports on the open sleeve 30A and treats the surrounding formation through perforations 15, cracks, fissures, exposed areas, etc.

This process is repeated for all the sleeves 30A-C in the well from the toe to the heel of the completion. If needed, a sand jet perforator (not shown) can be used to create additional zones. At the conclusion of the treatment, the coiled tubing 24 is pulled out of the well, leaving a monobore completion that can be used directly for production. The system 10 eliminates the need for milling operations after the stimulation, which could damage sensitive reservoirs.

Another system 10 illustrated in FIG. 2 uses coiled tubing 24, a resettable plug 50/70, and sliding sleeves 40/60, but the sleeves 40/60 are not shifted open mechanically with a shifting tool as before. Instead, different operations are performed to open the sliding sleeves 40/60 so that fluid can be communicated out of the casing 14 and into the formation surrounding the borehole 12.

In particular, FIG. 3A illustrates one example for the system 10 in FIG. 2 that uses coiled tubing 24, an isolation assembly 50, and a sliding sleeve 40. This example system is similar to that disclosed in US2013/0180721. The coiled tubing 24 deploys the isolation assembly 50 to the sliding sleeve 40 and opens the sleeve 40 using coiled tubing manipulation and applied pressure while the isolation assembly 50 is set inside the sliding sleeve 40.

In particular, the sleeve 40 is disposed on the casing (14) at a predetermined point where the formation is to be treated, and the sleeve 40 is cemented in the borehole along with the rest of the casing 14. When treatment is to be performed, the isolation assembly 50 disposed on the coiled tubing 24 deploys to the sleeve 40 to be opened. The isolation assembly 50 includes a treatment housing 51 with ports 56, a sand-jet perforating sub 58 with nozzles 59, an equalizing valve (not shown), a resettable plug 54, and a sleeve locator 52. A ball valve (not shown) is disposed between the first treatment housing 51 and jet perforation sub 58 for selecting output of fluid from the assembly 50.

The resettable plug 54 isolates the zone from the casing 14 below, mechanically shifts the sleeve 40 open, and anchors the isolation assembly 50 during fracture pumping. An automatic J-slot mechanism (not shown) sets, releases, and resets the assembly 50 with straight up/down coiled tubing motion. The integral equalization valve (not shown) facilitates releasing the plug 54, and the sand-jet perforating sub 58 can be used to add a stage in a blank section of the casing 14.

To fracture the formation, for example, the assembly 50 deploys as part of the coiled tubing 24 and positions below the sliding sleeve 40. The assembly 50 is then pulled upward, and the keys of the sleeve locator 52 engage a recess 46 at the end of the sleeve 40. The keys on the locator 52 snap into the recess 46, which gives a positive indication that the assembly 50 is properly positioned. Coiled tubing set-down weight then sets the resettable plug 54. The plug's slips grip inside the sleeve's insert 42, and the plug's packer element seals against the sleeve's insert 42 to seal off the lower casing 14. Operators increase pressure in the casing 14 and force the assembly 50 and the insert 42 down with the pressure, which opens the sleeve's ports 44 to the formation. When the insert 42 shifts, the recess 46 closes and forces the locator 52 to retract, indicating that the sleeve 50 has shifted open.

Operators pump fracture treatment down the annulus between the coiled tubing 24 and casing 14, although the fluid can be pumped through the coiled tubing 24 for lower rates. For example, fracturing fluid can be applied through the coiled tubing 24, exiting first ports 56 present in treatment housing 51 and resulting in the fracturing of the region around the sleeve's ports 44. Once the fluid has been pumped, operators pull on the coiled tubing 24 to open the integral equalizing valve (not shown) and unset the plug 54. The isolation assembly 50 can then be moved up to the next sleeve 40 so the sequence can be repeated for a new zone.

To add a stage, the isolation assembly 50 can be set in a blank section of the casing 14, and a perforation can be made. To do this, a ball can be dropped to prevent fluid flow down to the treatment housing 51. This results in fluid diversion to the nozzles 59 of the jet perforation sub 58. Operators pump sand-laden fluid down the coiled tubing 24 and out the nozzles 59 of the perforating sub 58 to cut through the casing 14 and cement and into the formation.

FIG. 3B illustrates a sliding sleeve 40 as disclosed in US 2012/0090847, which can be used with the system and assembly 50 of FIG. 3A. As specifically shown in FIG. 3B, a similar type of assembly 50 can also be used to mechanically shift the sliding sleeve 40. As depicted here, a casing collar locator 52 engages a corresponding profile 46 below the unshifted insert 42 within the ported sleeve 40. Once the collar locator 52 is engaged, a plug or seal 54 is set against the insert 42, aided by mechanical slips 55. When set, the seal 42 isolates the wellbore above the ported sleeve 40.

To open the sleeve 40, force and/or hydraulic pressure are applied to the work string (not shown) and packer 54 from uphole. The force and/or hydraulic pressure shears a shear pin 49 and shifts the insert 42 downward so that it engages the locator (52). As the sleeve's insert 42 shifts downhole, the collar locator 52 collapses, and the insert 42 exposes the ports 44 in the sleeve 40.

The applied force and/or pressure to open the insert 42 may be a mechanical force applied directly to the work string (and thereby to the engaged insert 42) from the surface, for example, using coiled tubing, jointed pipe, or other tubing string. The applied force and/or pressure to open the insert 42 may also be a hydraulic pressure applied against the seal 54 through the wellbore annulus and/or through the work string.

Once the ports 44 are open, treatment may be applied to the formation. For example, fracturing fluid can be applied through the coiled tubing 24, exiting ports 56 present in the assembly 50 to fracture the region around the sleeve's ports 44. After the sleeve 40 has been opened, the seal 54 and work string may remain set within the wellbore to isolate the ports 44 in the newly opened sleeve 40 from any previously opened ports below. Alternatively, the seal 54 may be unset for verifying the state of the opened sleeve 40, or to relocate the work string as necessary (for example to apply treatment fluid to the ports of one or more sleeves 40 simultaneously).

Depending on the configuration of the work string, treatment fluid may be applied to the ports 44 through one or more apertures in the assembly 50 or the work string, or via the wellbore annulus about the work string. If perforation is desired in a region of the casing 14 above the sleeve's ports 44, a ball can be dropped to prevent fluid flow down to the lower ports 56. This results in fluid diversion to the nozzles 59 of the assembly 50.

FIG. 3C illustrates another sliding sleeve 40 as disclosed in US 2012/0090847. This sleeve 40 has an annular channel 47 that extends longitudinally within the sleeve 40 between inner and outer housings 48a-b and intersects treatment ports 44. A valve 45 within the channel 47 is held over the treatment ports 44 by a shear pin 49. The channel 47 is open to the inner bore near each end at sleeve ports 41, 43. The valve 45 is generally held or biased to the closed position covering the port 44, but may be slidably actuated within the channel 47 to open the treatment port 44. For example, a seal (not shown) of an assembly may be positioned in the housing 48a between the sleeve ports 41, 43 to allow application of fluid to the upper sleeve port 41 (without corresponding application of hydraulic pressure through the lower sleeve port 43). As a result, the valve 45 slides within the channel 47 toward the opposing sleeve port 43, thereby opening the treatment port 44. Treatment may then be applied to formation through the port 44.

Compared to the systems of FIGS. 3A-3C, a similar system shown in FIG. 4A also uses coiled tubing 24, an isolation assembly 70, and sliding sleeves 60. This system is disclosed in US Pat. Pub. No. 2011/0308817. As shown, the sleeve 60 has ports 64 for fluid communication outside the sleeve 60. An insert 62 positioned in the sleeve 60 can be moved from a closed position to an opened position and can be held in the closed position with a shear pin 63.

The assembly 70 connects to the coiled tubing 24 and positions inside the sliding sleeve 60. A casing collar locator 72 may be used to locate the assembly 70 in the sleeve 60. For example, a lower cross-over attached to the sleeve 60 may include a profile 66 to engage the casing collar locator 72.

The assembly 70 has a packer 74 that may be activated to seal the annulus between the assembly 70 and the sleeve's insert 62. The assembly 70 also includes an anchor 75 that may be set against the insert 62. Application of pressure down the coiled tubing 24 activates the packer 74 and the anchor 75 and sets them against the insert 62.

After setting the packer 74 and the anchor 75, fluid pumped down the casing 14 creates a pressure differential across the packer 74. When a predetermined pressure differential is reached, the shear pin 63 shears and releases the insert 62 from the sleeve 60. The increased pressure differential across the packer 74 then moves the assembly 70 anchored to the insert 62 down the sleeve 60. In this way, the insert 62 can be moved from the closed position to the open position. After the insert 62 has been opened, the assembly 70 may be released, moved up the casing 14 to the next desired zone, and set within another sleeve 60 as before.

Yet another similar system shown in FIG. 4B also uses coiled tubing (not shown), an isolation assembly 70, and a sliding sleeve 60. This system is also disclosed in US Pat. Pub. No. 2011/0308817 and is similar to what is disclosed in SPE 143250, entitled “Cased-Hole Multi-Stage Fracturing: A new Coiled Tubing Enabled Completion” by John Ravensbergen. The fracture sleeve 60 is a pressure-balanced device that opens when subjected to a pressure differential. As shown, the sleeve 60 has ports 64, vent holes 63a-b, and a valve 65, which can be moved from a closed to an opened position.

As before, the sleeve 60 is run as part of the casing 14 cemented in the borehole. As specifically shown in FIG. 4B, the sleeve 60 made up to the casing 14 has a mandrel 61a, a valve housing 61b, and a vent housing 61c. The valve 65 is positioned within an annulus 67 between the mandrel 61a and the valve housing 61b. The sleeve 65 is movable to an open position (shown in FIG. 4B) that permits communication out of the mandrel 61a through ports 64. In a closed position, the valve 65 is held by the shear pin 69. The mandrel 61a may include one or more ports 63a that are positioned uphole of the closed valve 65 to aid in the application of a pressure differential into the annulus 67 above the valve 65 when moving the valve 65 to the open position.

To fracture the formation adjacent the sleeve 60, the assembly 70 is positioned in the sleeve 60 while the pressure balanced valve 65 is initially closed. A casing collar locator (not shown) can be used on the end of the assembly 70 to position the assembly 70 in the sleeve 60. To create a pressure differential, an isolation packer 74 is set inside the sleeve 60 and pressure is applied from the surface in the casing 14 so that a pressure differential is generated across the sleeve 60. When the differential exceeds a predetermined level, shear pin 69 breaks, and the valve 65 shifts open.

As shown, the packer 74 can be positioned between the ports 63a-b. When the packer 74 is energized, it seals inside the sleeve 60 to prevent fluid flow further downhole. Thus, when fluid flows downhole from surface in the annulus between the casing 14 and the assembly 70, a pressure differential is formed across the packer 74 between the ports 63a-b, which opens the valve 65. After opening the valve 65 and fracturing the wellbore, the valve 65 may be moved back to the closed position upon the application of a reverse pressure differential.

As indicated above, a number of systems have been used for treating zones of a formation with assemblies deployed on coiled tubing. These assemblies use mechanical shifting to open sliding sleeves (e.g., FIG. 1) or use packers and hydraulic pressure to open the sliding sleeves (e.g., FIGS. 2 through 4B). Although such systems are useful, some problems still remain. For example, the sliding sleeves can be deployed as port collars on the casing in the borehole and may be cemented in place. Under these conditions, opening the sliding sleeves may be complicated by residual cement.

Additionally, some of the systems require weight to be available at the end of the coiled tubing so the available weight can be used to initiate setting of a packer, shifting the sleeve, or some other operation. Because the coiled tubing may be deployed in a deviated of horizontal well, an overwhelming amount of sinusoidal and helical buckling may occur in the coiled tubing, which minimizes the functionality of the system at the toe of the well. Historically, the ability to reach extended horizontal length has been gained by circulating down friction reducing agents, using mechanical agitators to break friction, etc. Yet even with such extended reach, the capabilities at the end of the coiled tubing may still be limited.

What is needed is a system that can reliably reach and function at extended lengths in a horizontal well. The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.

SUMMARY OF THE DISCLOSURE

A system is used for treating a formation of a borehole having casing. The system has a sleeve, a motor, and a packer. The sleeve is disposed on the casing in the borehole and has a port communicating out of the sleeve. An insert disposed in the sleeve is movable in the sleeve from closed to opened positions relative to the port. The motor is deployed in the casing with coiled tubing and is operable to impart rotation. The packer is operatively coupled to the motor. In response to the rotation imparted by the motor, the packer sets in the insert of the sleeve and moves the insert to the opened condition.

The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a first fracturing system according to the prior art using a packer and shifting tool on coiled tubing for manipulating sliding sleeves.

FIG. 2 illustrates a second fracturing system according to the prior art using an isolation assembly on coiled tubing for manipulating sliding sleeves.

FIG. 3A illustrates a prior art system as in FIG. 2 that uses coil tubing, an isolation assembly, and a sliding sleeve.

FIG. 3B illustrates a prior art sliding sleeve for the system as in FIG. 2.

FIG. 3C illustrates another prior art sliding sleeve for the system as in FIG. 2.

FIG. 4A illustrates another prior art system as in FIG. 2 that uses coil tubing, an isolation assembly, and a sliding sleeve.

FIG. 4B illustrates yet another prior art system as in FIG. 2 that uses coil tubing, an isolation assembly, and a sliding sleeve.

FIG. 5 illustrates a fracturing system according to the present disclosure using a resettable packer and a motor on coiled tubing for manipulating sliding sleeves.

FIGS. 6A-6B illustrate a motor and a packer for use on the coiled tubing in the disclosed fracturing system.

FIGS. 7A-7B illustrate a sleeve according to the present disclosure in closed and open conditions.

FIGS. 8A-8C illustrate guide components for the inserts in the sliding sleeves of the present disclosure.

FIG. 9A-9D illustrate operational stages of the disclosed system.

DETAILED DESCRIPTION OF THE DISCLOSURE

Referring to FIG. 5, a fluid treatment system 10 of the present disclosure is illustrated in a borehole 12. The fluid treatment system 10 can be a fracturing system for fracturing a formation, can be a steam injection system, or can be any other type of fluid treatment system known and used in the art. Although the borehole 12 is shown as being vertical, the borehole 12 can be, and most likely is, a horizontal or deviated borehole. A casing or liner 14 is cemented in the borehole 12 using standard procedures so cement 16 supports the casing 14 in the borehole 12. At suitable zones along the borehole 12, sliding sleeves or port collars 100A-C are disposed in closed conditions on the casing 14. When the casing 14 is cemented, these sleeves 100A-C are cemented in place along with the casing 14.

To perform a treatment (fracture) operation, operators deploy an assembly having a motor 130 and a packer 150 on coiled tubing 24 down the casing 14 to selectively open the sliding sleeves 100A-C. As will be described in more detail below, the packer 150 is deployed inside one of the sleeves 100A to be set therein. Operators start a pump in a pumping system 22 at the surface to operate the downhole motor 130, which rotates and sets the packer 150 in the given sleeve 100A. As the set packer 150 continues to rotate, the sleeve 100A opens from a closed position to an opened position. Once the sleeve 100A is open, the packer 150 can then remain in the sleeve 100A or can be unset and moved elsewhere.

Either way, the pumping system 22 pumps a treatment fluid to treat the formation through the opened sleeve 100A. The treatment can be pumped down the casing 14 in the annulus around the coiled tubing 24 or can be pumped down the coiled tubing 24. This process of opening sleeves 100A-C and treating the formation is repeated in the casing 14 to treat the various zones. Of course, because the sliding sleeves 100A-C can be selectively opened, treatment of the various zones can be performed in any desired order or combination.

At some point during operations, flow through the coiled tubing 24 may need to be diverted so that it does not reach the motor 130 and packer 150. For example, treatment fluid can be pumped through the coiled tubing 24, if desired. For this reason, a sequencing valve (170) can be run above the motor 130. The flow needed to operated the sequencing valve (170) can be several times the flow required to operate the motor 130 so that at high flow rates the valve (170) opens and diverts flow away from the motor 130. Additionally, because the coiled tubing 24 may be deployed at an extended depth in horizontal or deviated wells, an agitator (180), such as available from Andergauge Drilling Systems, can be run on the coiled tubing 24 to move the coiled tubing 24 for operating in a borehole having extended reach. The type of agitator (180) used and its location in the system 10 can vary depending on the implementation.

The system 10 may also include a jet cutting assembly (not shown) for perforating the casing 14 at a location in the borehole 12. Such a jet cutting assembly can be similar to those used in the art and may be selectively activated using any number of available techniques. The system 10 may also include a casing cutter (not shown) to create a new zone or open the casing 14 when a sleeve fails. Such a casing cutter can be operated with the motor's rotation and may be selectively activated using any number of available techniques.

The system 10 eliminates the need for any weight at the toe of the well. The system 10 can still employ all of the known methods for extending the coiled tubing 24 out as far as possible in an extended reach well. However, the necessary weight needed to initiate setting of the packer 150 and shifting of the sleeves 100A-C is not needed in the disclosed system 10.

With the benefit of the above overview of the system 10, its components, and its operation, discussion now turns to further details of the motor 130 and the packer 150 (with reference to FIGS. 6A-6B) and to further details of the sliding sleeve 100 (with reference to FIGS. 7A-7B).

Turning first to FIGS. 6A-6B, an assembly has the downhole motor 130 and the packer 150 for use on the coiled tubing (24) in the disclosed system. The motor 130 is a downhole motor operated by the flow of fluid conveyed by the coiled tubing (24) to a power section 132 of the motor 130. The packer 150 is a rotate-to-set type of packer and can be used to opening the sliding sleeve 100 and seal off fluid flow.

As examples, the coiled tubing 24 can be 2⅜″ coiled tubing. The motor 130 can be similar to a type of milling motor conveyable on coiled tubing. For example, the motor 130 can be similar to 2⅛″ CTD motor available from Weatherford International Ltd. The max torque of such a motor may be 438 ft-lbs (594 N-m), and a max flow of such a motor can be up to 13.2 gallons/minute (50 LPM). The max tensile load can be 18,250 lbs (81,180 N). The desired revolutions per minute (RPM) produced by the motor 130 may only need to be relatively low, such as from 5 to 10 RPM. These characteristics along with the revolutions per minute produced with the motor 130 can be appropriately adjusted for the implementation so that the motor 130 is adapted to set and unset the packer 150 and to open the sleeves 100A-C.

As shown in FIG. 6B, the power section 132 of the motor 130 can have a rotor 133a that rotates in a stator 133b when fluid flows between them. A transmission section 134 transfers the rotation from the power section 132 to a drive mandrel 140, which is supported by a bearing section 136 in the motor 130. Fluid flow from the motor's uphole end 131, which couples to the coiled tubing (24) or other component, travels through the power section 132 and the transmission section 134 and eventually enters a flow bore 142 of the mandrel 140—beyond which extends the packer 150.

For its part, the rotate-to-set type packer 150 can be similar to Weatherford's Ultra-Lok packer or other type of Lok-set packer. The packer 150 is retrievable, and the packing element 156 is set by compression. Preferably, rotation sets and releases the packer 150. For example, the packer 150 can have a mandrel 152 coupled to the drive mandrel 140 of the motor 130. Disposed on the mandrel 152, the packer 150 can have a housing 155, a packing element 156, biased locators 157, and biased drag blocks or grips 158.

The packing element 156 is configured to set using the rotation from the motor 130. In particular, the biased locators 157 can be used to locate the packer 150 in a sliding sleeve (100A-C). The mandrel 152 can be rotated and includes external threads 153 on which a ratchet 154 rides to move the housing 155 on the mandrel 152 to compress the packing element 156. The biased drag blocks 158 can engage against a surrounding sidewall to prevent the housing 155 from rotating with the mandrel 152. Once set in the sleeve (100A-C), the packer 150 rotates the sleeve (100A-C) open, as discussed in more detail below. When set, the packer 150 may also be capable of handling a suitable pressure rating (e.g., 8-KSI) for treatment to be applied. Releasing the packer 150 may require pulling by the coiled tubing (24) while rotating, which can unset the packing element 156 and release the packer 150.

Turning now to FIGS. 7A-7B, a sliding sleeve or port collar 100 according to the present disclosure is shown in a closed condition (FIG. 7A) and an open condition (FIG. 7B). The sleeve 100 installs in a conventional way on uphole and downhole sections of tubing or casing (14). The sleeve 100 has a housing 102 with a bore 104 passing therethrough. An insert 110 is movable in the bore 104 relative to ports 105 defined in the housing 102. When the insert 110 is in the closed condition (FIG. 7A), flow out of the sleeve 100 through the ports 105 is prevented. When the insert 110 is in the opened condition (FIG. 7B), the ports 105 can communicate fluid from the bore 104 outside the sleeve 100 to treat the formation.

The sleeve 100 can also include various other conventional features. For example, detents (not shown) can be formed at positions in the bore 104 for engaging lock tabs (not shown) on the insert 110. Seals 114 on the insert 110 can seal off the exit ports 105 when the insert 110 is in the closed condition (FIG. 7A). These and other conventional features may be present on the sleeve 100.

As best shown in the closed condition of FIG. 7A, an internal rotational guide 106 is defined along a portion of the inside surface of the housing's bore 104. A portion of the external surface of the insert 110 has one or more external rotational guides 116 (e.g., a pin, a profile, a dog, etc.). The external guides 116 complement the internal guide 106 and ride in the internal guide 106 so that rotation of the insert 110 inside the bore 102 moves the insert 110 down along the internal guide 106 to the opened condition (FIG. 7B).

As shown here, the internal guide 106 can be a female feature, such as a slot, a channel, a groove, a cam, a worm gear, or the like, that spirals helically around the inside surface of the housing's bore 104. The external guide 116 on the insert 110 can be a male feature, such as a pin, a bearing, a dog, a profile, etc. on the insert 110 that can ride in the internal guide 106 as the insert 110 is engaged by the packer (150) and is rotated by the motor (130).

As shown in FIG. 7A, the insert 110 of the sleeve 100 preferably starts in the uphole, closed position. The sleeve 100 is installed having the internal guide 106 packed with high-temperature, intumescent silicone prior to installation. This can help protect the internal guide 106 during cementing and other operations. Rotation of the insert 110 moves the insert 110 in the sleeve 100 to the opened condition shown in FIG. 7B.

As shown, the guides 106 and 116 lead the insert 110 to concurrently rotate and axially displace in the housing's bore 104. As one alternative, the insert 110 may merely move from a closed to an open position by rotation imparted by the motor (130). Also, the insert 110 may be opened by first rotation from the motor 130 and then by separate axial displacement by applied pressure.

In the sliding sleeve 100 as shown, the ports 105 may be disposed uphole of the internal guide 106 inside the housing's bore 104. The reverse is also possible where the insert 110 moves uphole in the sleeve's bore 104 to open the ports 105 further downhole. In this case, setting and unsetting of the packer 150 during operations may need to be modified to accommodate such a reverse arrangement.

FIGS. 8A-8C illustrate a number of examples for the internal and external guides 106 and 116 that can be used between the insert 110 and the housing 102. In FIG. 8A, the internal guide 106 is a slot that spirals helically around the inside surface of the housing's bore 104. The external guide 116 is a pin 117a disposed on the external surface of the insert 110. Rotation of the insert 110 moves the pin 117a in the slot 106 so that the rotation of the insert 110 is guided axially along the housing's bore 104.

In FIG. 8B, the internal guide 106 is again a slot that spirals helically around the inside surface of the housing's bore 104. The external guide 116 is a biased pin 117ba disposed on the external surface of the insert 110. Additionally as shown in FIG. 8C, the internal guide 106 is a bearing groove that spirals helically around the inside surface of the housing's bore 104, and the external guide 116 is a bearing 117c disposed in a bearing detent on the external surface of the insert 110.

Although the internal guide 106 has been shown above as a female feature and the external guide 116 has been shown as a male feature, a reverse arrangement can be used. For example, any of the various slots or bearing grooves shown in FIGS. 8A-8C above can be defined around the exterior surface of the insert 110, and any pins, bearings, and the like can be disposed on the interior surface of the sleeve's bore 104. Moreover, an arrangement having mutually complementary features (i.e., a thread) can be used. As will be appreciated, the length, pitch, and other aspects of the guides 106 and 116 can be adjusted for the particular friction, RPMs, torque, and other specifications of a given implementation. In fact, rotation and axial displacement along the guides 106 and 116 can be coordinated with known rotation of the motor 130 so that the insert 110 can be adjustably opened relative to the ports 105. This can allow operators to vary the amount of port area 105 opened in a given sleeve 100 to achieve any suitable treatment purpose, such as a limited entry perforation.

With an understanding of the components of the system 10, further details of a treatment operation performed with the disclosed system 10 are discussed. As noted above with reference to FIG. 5, the borehole 12 is lined with casing 14 having the sleeves 100A-C disposed at particular zones or areas of the formation to be treated. The casing 14 and the sleeves 100A-C can be cemented in place in the borehole 12. Alternatively, other forms of isolation, such as casing annulus packers, may be used in the open borehole 12 to isolate one zone from another.

Either way, the ports 105 on the sleeves 100A-C can communicate with the formation during treatment operations when the sleeves 100A-C are open. Opening and closing the sleeves 100A-C is discussed below. Any cement around the exposed ports 105 when the sleeves 100A-C are opened can be removed using standard techniques, such as jet cutting, acidizing, dissolving, breaking with pressure, etc.

To begin a treatment operation, operators deploy the motor 130 and the packer 150 on the coiled tubing 24 down the casing 14. As shown in FIG. 9A, the packer 150 deploys inside the insert 110 of one of the sleeves 100 to be opened. Operators start a pump in the pumping system (22) at the surface to operate the motor 130 and to set the packer 150 in the insert 110 of the sleeve 100.

As shown in FIG. 9B, for example, the packer 150 is located in the insert 110 with the locators 157. The packer 150 is then rotated by the motor 130 and is set by engaging the drag blocks 158 inside the sleeve 100. As the motor 130 continues to rotate the packer's mandrel 152 while the drag blocks 158 hold the packer's housing 155, the packing element 156 can be compressed to extend outward and engage inside the insert's internal surface 112.

Eventually, the motor 130 sets the packer 150 in the insert 110 so that rotation of the motor 130 rotates the packer 150 and the insert 110 together. As the set packer 150 rotates, the insert 110 on the sleeve 100 rides along the internal guide 106 and opens to expose the external ports 105, as shown in FIG. 9C. As will be appreciated, because the packer 150 is set inside of the insert 110, rotation of the packer 150 by the motor 130 transmits the torque to the insert 110, turning it around the internal guide 106 and eventually axially displacing it to the open position. Fluid pressure in the casing 14 can be applied against the set packer 150 to assist this movement of the insert 110.

Once the sleeve 100 is open, a fluid treatment can be performed. Depending on whether any other sleeves 100 downhole on the casing 14 have been closed after being previously opened, then the packer 150 may or may not remain set in the insert 110. For example, if desired, the packer 150 may remain set in the insert 110 to at least partially prevent further communication of fluid treatment down the casing 14 past the packer 150.

Alternatively, if previously opened sleeves 100 further downhole on the casing 14 have been closed, then it is possible to remove the packer 150 from the insert 100 and proceed with treatment. To do this, operators pull the coiled tubing 24 into tension and continue to rotate the motor 130 to unset the packer 150. Any tension shoulder on the sleeve 100A is set above what is required to unset the packer 150. The packer 150 and motor 130 may then be run further downhole away from the open ports 105 of the sleeve 100, as shown in FIG. 9D, for example.

Likewise, if a lower sleeve (100) was not closed in previous operations, operators can run the motor 130 and packer 150 downhole, as shown in FIG. 9D, and can position it in a joint below. At this point, the packer 150 can then be set in the casing 14 to isolate the currently opened sleeve 100 from zones further downhole on the casing 14.

Either way, operators can perform the treatment operations by pumping fluid down the casing 14 so that the treatment fluid exits the opened ports 105 on the sleeve 100 and treats the formation through perforations, cracks, or the like in the cement (16). Alternatively, treatment can be pumped down the coiled tubing (24) and may be directed to the casing 14 and open ports 105 using any of a number of techniques, valves, and other devices. As discussion previously, for example, the sequencing valve (170: FIG. 5) disposed on the coiled tubing (24) upstream of the motor 130 may direct treatment fluid from the coiled tubing (24) into the casing 14 for passaged into the open ports 105. In another alternative, the motor 130 may have an internal bypass for passage of the treatment fluid therethrough to beyond the packer 150. These and other variations can be used.

If the packer 150 has remained set in the sleeve 100 or has been set elsewhere further downhole, operators pull the coiled tubing 24 in tension and unset the packer 150 with pressure maintained on the casing 14. Finally, the packer 150 can be unset and moved to the next sleeve 100 on the casing 14. As before, the packer 150 is located inside the insert 110 of the next sleeve 100 so the sleeve 100 can be opened by rotation with the motor 130. The entire process is then repeated as before in the casing 14 to treat the desired zones.

Once treatment is completed at a particular zone, the sleeve 100 may remain open or may be closed. For example, to close the insert 100, the packer 150 can be pulled uphole and can be reset in the insert 110 of the sleeve 100 so tension can be pulled on the coiled tubing 24 to close the insert 110 in the sleeve 100. Also, the insert 110 may include a standard profile (not shown) (e.g., a standard B shifting tool profile at the uphole end of the insert 110) or other feature so that a shifting tool could be used to engage the insert 110 and move it closed. To be able to pull or move the insert 110 closed, the insert 110 can use a ratcheted release to allow the insert 110 to be pulled closed without needing to rotate along the internal guide 106.

Briefly, one example for such a ratcheted release is shown in FIG. 8B. As shown, the biased pin 117b can be beveled so that upward movement pushes the pin 117b out of the slot 106. The insert 110 can then be ratcheted upward in the housing's bore 104 to a closed condition. If desired, the sleeve 100 may also include a mechanism for limiting the closing of the insert 110 in the sleeve 100 so the insert 110 can be held or locked at least partially open relative to the ports 105. As will be appreciated, any various lock features common to sliding sleeves can be used to hold or lock the insert 110 in place.

As will be appreciated, the terms of “sliding sleeve” and “port collar” may be used interchangeably throughout as referring in general to the same type of device. Additionally, although the sleeves have been disclosed herein as being deployed on casing and as being cemented in a borehole, this is not strictly necessary. Instead, the sleeves can be disposed on any suitable tubular for positioning in the well and may or may not be cemented in place. Finally, the terms “insert” and “sleeve” may be used interchangeably throughout to refer to the movable element within a housing for opening and closing fluid communication through the housing's external ports.

Although the motor may be a milling motor operated by fluid flow through a stator and rotor arrangement, any other type of hydraulic motor can be used. Additionally, even though a hydraulically operated motor may be preferred for the disclosed assembly, any type of motor can be used, including an electric motor, a hydraulic motor, a mud motor, a positive displacement motor, a Moineau motor, a Moyno® motor, a turbine type motor, or other type of downhole motor.

Moreover, the system disclosed above of using a packer and a motor on coiled tubing to open sliding sleeves has been specifically described with reference to fluid treatment. As will be appreciated with the benefit of the present disclosure, the teachings of the system disclosed herein can be applied to any suitable operation in which a sliding sleeve can be opened (and optionally closed) using coiled tubing. As but one example, the sleeves may provide rotationally accessible windows for multi-lateral applications, or the sleeves may provide inlets and/or outlets for any other suitable downhole application (e.g., completion, production, injection, treatment, etc.) in a borehole.

The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. It will be appreciated with the benefit of the present disclosure that features described above in accordance with any embodiment or aspect of the disclosed subject matter can be utilized, either alone or in combination, with any other described feature, in any other embodiment or aspect of the disclosed subject matter.

In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof.

Claims

1. A system using coiled tubing for treating a formation of a borehole having casing, the system comprising:

at least one sleeve disposed on the casing in the borehole, the at least one sleeve having at least one port communicating outside the at least one sleeve and having an insert disposed in the at least one sleeve, the insert movable in the at least one sleeve at least from a closed position to an opened position relative to the at least one port;

a motor deployed in the casing with the coiled tubing and being operable to impart rotation; and

a packer operatively coupled to the motor, the packer, in response to the rotation imparted by the motor, engaging in the insert of the at least one sleeve and moving the insert at least to the opened condition.

2. The system of claim 1, wherein the insert and the sleeve comprise means for guiding rotation and axial displacement of the insert moving in the at least one sleeve at least from the closed position to the opened position.

3. The system of claim 1, wherein the at least one sleeve comprises an internal guide disposed thereon and guiding movement of the insert in the at least one sleeve; and wherein the insert comprises an external guide disposed thereon and movable along the internal guide of the at least sleeve.

4. The system of claim 3, wherein the internal guide defines a slot formed around an inside surface of the at least one sleeve; and wherein the external guide comprises a pin disposed on an external surface of the insert and movable along the slot.

5. The system of claim 1, wherein the insert rotates and displaces axially in the at least one sleeve when moving from the closed position to the opened position.

6. The system of claim 1, wherein the packer comprises at least one grip movable on the packer to an extended condition to engage the insert.

7. The system of claim 1, wherein the packer comprises at least one packing element disposed on the packer and being compressible to engage inside the insert.

8. The system of claim 1, wherein the motor comprises a hydraulic motor operable by flow of fluid from the coiled tubing through the motor.

9. The system of claim 1, further comprising a valve in communication between the coiled tubing and the motor, the valve being operable to direct fluid flow from the coiled tubing away from the motor.

10. The system of claim 1, further comprising an agitator operable to agitate the coiled tubing.

11. The system of claim 1, wherein the insert is movable in the at least one sleeve from the opened position to the closed position.

12. The system of claim 11, wherein to move from the closed position to the opened position, a guide component disposed between the at least one sleeve and the insert guides rotation and axial displacement of the insert in the at least one sleeve; and wherein to move from the opened position to the closed position, the guide component permits the axial displacement of the insert in the at least one sleeve.

13. A sleeve for fluid communication on tubing, the sleeve comprising:

a housing having first and second ends coupling to the tubing and having a bore therethrough, the housing defining at least one port communicating the bore outside the housing;

an insert disposed in the bore of the housing and being movable inside the bore at least from a closed position to an opened position relative to the at least one port; and

a guide component disposed between the housing and the insert and guiding rotation and axial displacement of the insert moving from the closed position to the opened position.

14. A system using coiled tubing for treating a formation of a borehole through at least one sleeve disposed on casing in the borehole, the at least one sleeve having an insert disposed therein, the insert movable in the at least one sleeve at least from a closed position to an opened position relative to at least one port, the system comprising:

a motor deployed in the casing with the coiled tubing and being operable to impart rotation; and

a packer operatively coupled to the motor, the packer, in response to the rotation imparted by the motor, engaging in the insert of the at least one sleeve and moving the insert at least to the opened condition with the rotation imparted by the motor.

15. A method using coiled tubing for treating a formation of a borehole having casing with at least one sleeve disposed thereon, the method comprising:

deploying a motor and a packer in the casing with the coiled tubing;

engaging the packer in an insert of the at least one sleeve;

imparting rotation to the packer with the motor;

moving the insert of the at least one sleeve from a closed position to an opened position with the imparted rotation of the engaged packer; and

treating the formation through at least one port of the opened sleeve.

16. The method of claim 15, wherein engaging the packer in the insert of the at least one sleeve comprises rotating one portion of the packer relative to another portion of the packer and compressing a compressible packing element on the packer against an inside surface of the insert.

17. The method of claim 15, wherein imparting the rotation to the packer with the motor comprises pumping fluid to the motor through the coiled tubing and rotating the packer with the rotation from the motor.

18. The method of claim 15, wherein moving the insert of the at least one sleeve from the closed position to the opened position with the imparted rotation of the engaged packer comprises guiding rotation and axial displacement of the insert with a guide component disposed between the insert and the at least one sleeve.

19. The method of claim 15, further comprising unsetting the packer from the insert either before or after treatment.

20. The method of claim 19, wherein unsetting the packer comprises pulling tension on the coiled tubing and imparting rotation to the packer with the motor.

21. The method of claim 19, wherein, after unsetting the packer before treatment, the method comprises deploying the motor and the packer on the coiled tubing downhole of the at least one port in the opened sleeve.

22. The method of claim 19, further comprising setting the packer in the casing downhole of the at least one port in the opened sleeve.

23. The method of claim 15, wherein treating the formation through the at least one port of the opened sleeve comprises pumping treatment down the casing.

24. The method of claim 15, further comprising moving the insert from the opened position to the closed position in the sleeve.

25. The method of claim 24, wherein moving the insert from the opened position to the closed position in the sleeve comprising pulling up the insert with tension of the coiled tubing on the engaged packer in the insert.