Patent Publication Number: US-2015083440-A1

Title: Rotatably-Actuated Fluid Treatment System Using Coiled Tubing

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  30 A-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  30 A-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  30 A-C and with the packer  40  and shifting tool  45  on the single coiled-tubing bottomhole assembly (BHA). In the system  10 , the sleeves  30 A-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  30 A-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  30 A, and operators pull up on the tubing  24  to open the insert on the sleeve  30 A to expose external ports. 
     Operators then run the packer  40  into the joint below the open sleeve  30 A 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  30 A and treats the surrounding formation through perforations  15 , cracks, fissures, exposed areas, etc. 
     This process is repeated for all the sleeves  30 A-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&#39;s slips grip inside the sleeve&#39;s insert  42 , and the plug&#39;s packer element seals against the sleeve&#39;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&#39;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&#39;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&#39;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&#39;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&#39;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  48   a - 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  48   a  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&#39;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  63   a - 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  61   a , a valve housing  61   b , and a vent housing  61   c . The valve  65  is positioned within an annulus  67  between the mandrel  61   a  and the valve housing  61   b . The sleeve  65  is movable to an open position (shown in  FIG. 4B ) that permits communication out of the mandrel  61   a  through ports  64 . In a closed position, the valve  65  is held by the shear pin  69 . The mandrel  61   a  may include one or more ports  63   a  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  63   a - 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  63   a - 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  100 A-C are disposed in closed conditions on the casing  14 . When the casing  14  is cemented, these sleeves  100 A-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  100 A-C. As will be described in more detail below, the packer  150  is deployed inside one of the sleeves  100 A 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  100 A. As the set packer  150  continues to rotate, the sleeve  100 A opens from a closed position to an opened position. Once the sleeve  100 A is open, the packer  150  can then remain in the sleeve  100 A 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  100 A. 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  100 A-C and treating the formation is repeated in the casing  14  to treat the various zones. Of course, because the sliding sleeves  100 A-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&#39;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  100 A-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  100 A-C. 
     As shown in  FIG. 6B , the power section  132  of the motor  130  can have a rotor  133   a  that rotates in a stator  133   b  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&#39;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&#39;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 ( 100 A-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 ( 100 A-C), the packer  150  rotates the sleeve ( 100 A-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&#39;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&#39;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&#39;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&#39;s bore  104 . The reverse is also possible where the insert  110  moves uphole in the sleeve&#39;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&#39;s bore  104 . The external guide  116  is a pin  117   a  disposed on the external surface of the insert  110 . Rotation of the insert  110  moves the pin  117   a  in the slot  106  so that the rotation of the insert  110  is guided axially along the housing&#39;s bore  104 . 
     In  FIG. 8B , the internal guide  106  is again a slot that spirals helically around the inside surface of the housing&#39;s bore  104 . The external guide  116  is a biased pin  117   ba  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&#39;s bore  104 , and the external guide  116  is a bearing  117   c  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&#39;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  100 A-C disposed at particular zones or areas of the formation to be treated. The casing  14  and the sleeves  100 A-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  100 A-C can communicate with the formation during treatment operations when the sleeves  100 A-C are open. Opening and closing the sleeves  100 A-C is discussed below. Any cement around the exposed ports  105  when the sleeves  100 A-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&#39;s mandrel  152  while the drag blocks  158  hold the packer&#39;s housing  155 , the packing element  156  can be compressed to extend outward and engage inside the insert&#39;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  100 A 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  117   b  can be beveled so that upward movement pushes the pin  117   b  out of the slot  106 . The insert  110  can then be ratcheted upward in the housing&#39;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&#39;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.