Abstract:
An assembly for performing multiple downhole hydraulic stimulation applications in a well. The different applications may be performed without removal of the assembly from the well between the different applications. So, for example, even a hydraulic perforating application may be performed with prior or subsequent clean-out applications. Yet, there is no need to remove the assembly for manual surface adjustment of the hydraulic perforating tool in order to allow for such clean-outs. Thus, the time to run such multi-stage stimulation operations may be dramatically reduced.

Description:
FIELD 
       [0001]    Embodiments described relate to stimulation operations in downhole production zones of a well. More specifically, multi-stage hydraulic isolating, perforating, clean-out and fracturing tools and techniques are detailed. Such multiple applications may even be performed on a single wellbore tubular trip into the well delivering an embodiment of a hydraulic treatment assembly therefor. 
       BACKGROUND 
       [0002]    The statements in this section merely provide background information related to the present disclosure and may not constitute prior art. 
         [0003]    Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. As a result, over the years well architecture has become more sophisticated where appropriate in order to help enhance access to underground hydrocarbon reserves. For example, as opposed to wells of limited depth, it is not uncommon to find hydrocarbon wells exceeding 30,000 feet in depth. Furthermore, as opposed to remaining entirely vertical, today&#39;s hydrocarbon wells often include deviated or horizontal sections aimed at targeting particular underground reserves. 
         [0004]    While such well depths and architecture may increase the likelihood of accessing underground hydrocarbons, other challenges are presented in terms of well management and the maximization of hydrocarbon recovery from such wells. For example, during the life of a well, a variety of well access applications may be performed within the well with a host of different tools or measurement devices. However, providing downhole access to wells of such challenging architecture may require more than simply dropping a wireline into the well with the applicable tool located at the end thereof. Thus, wellbore tubulars such as coiled tubing are frequently employed to provide access to wells of such challenging architecture. 
         [0005]    Coiled tubing operations are particularly adept at providing access to highly deviated or tortuous wells where gravity alone fails to provide access to all regions of the wells. During a coiled tubing operation, a spool of pipe (i.e., a coiled tubing) with a downhole tool at the end thereof is slowly straightened and forcibly pushed into the well. This may be achieved by running coiled tubing from the spool and through a gooseneck guide arm and injector which are positioned over the well at the oilfield. In this manner, forces necessary to drive the coiled tubing through the deviated well may be employed, thereby delivering the tool to a desired downhole location. 
         [0006]    With different portions of the well generally accessible via coiled tubing, stimulation of different well zones may be carried out in the form of perforating and fracturing applications. For example, a perforating gun may be suspended at the end of the coiled tubing and employed for forming perforations through the well wall and into the surrounding formation. Subsequent hydraulic fracturing applications may be undertaken in order to deliver proppant and further encourage hydrocarbon recovery from the formation via the perforations. 
         [0007]    In some circumstances, a hydraulic jetting tool may be substituted for a more conventional perforating gun. A hydraulic jetting tool may comprise a solid body tool with jetting ports through sidewalls thereof and a ball seat positioned therebelow. Thus, once the tool is located at the target location for perforating, a ball may be pumped from surface and landed on the seat, thereby activating hydraulic jetting through the ports. Such a tool may be utilized where the nature of the surrounding formation dictates more effective perforating via a jetting tool. 
         [0008]    Regardless of the particular perforating tool employed, the sequential nature of stimulation remains substantially the same. That is, coiled tubing is outfitted with a perforating tool which is delivered downhole to a target location to form perforations. The coiled tubing is then withdrawn from the well and the perforating tool swapped out for a hydraulic fracturing tool which is subsequently delivered to the same target location for follow-on fracing. However, even where the perforating tool is a hydraulic jetting tool, it may not subsequently be employed for the lower pressure hydraulic fracturing. That is to say, once the ball has landed, it is stably and irreversibly held in place while the tool is downhole, so as to ensure reliable jetting through the ports. 
         [0009]    Unfortunately, the time it takes to run into and out of the well with the coiled tubing for the different stages of the stimulation can be quite costly, particularly when considering wells of greater depths or more challenging architectures. For example, it is not uncommon today to see wells of 10 to 20 different stimulated zones. Considering that in an offshore environment it may take on average about a week per zone to complete stimulation, the repeated trips into the well for tool change-outs may add up to several hundred thousand dollars of lost time. This is particularly true when considering the additional time required where clean-out between perforating and fracturing is undertaken or when considering separate well trips for zonal isolation in advance of stimulation. 
       SUMMARY 
       [0010]    A method of performing an application in a well is detailed. The application takes place through a wellbore tubular which is utilized to deliver an assembly with a ported tool to a target location. Ports of the tool may be opened for a first hydraulic treatment of the location at a first hydraulic setting. The tubular is then retained in the well to perform a second hydraulic treatment with the assembly at a second hydraulic setting. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0011]      FIG. 1  is a schematic front view of an embodiment of a multi-stage hydraulic treatment assembly for performing various downhole applications on a single trip into a well. 
           [0012]      FIG. 2  is a side cross-sectional schematic view of a hydraulic perforating tool of the treatment assembly of  FIG. 1 . 
           [0013]      FIG. 3  is an schematic overview of an oilfield having a well accommodating the treatment assembly of  FIG. 1  therein. 
           [0014]      FIG. 4A  is an enlarged depiction of a horizontal section of the well of  FIG. 3  having a mechanical packer of the treatment assembly set therein. 
           [0015]      FIG. 4B  is an enlarged depiction of a vertical section of the well of  FIG. 3  having perforations formed thereat via the perforating tool of the assembly. 
           [0016]      FIG. 4C  is an enlarged view of a clean-out application by a fracturing tool of the assembly directed at the perforations of  FIG. 4B . 
           [0017]      FIG. 5  is an enlarged view of a perforation taken from  5 - 5  of  FIG. 4C  revealing frac-matrix support following a fracturing application with the fracturing tool. 
           [0018]      FIG. 6  is a flow-chart summarizing an embodiment of employing a multi-stage downhole hydraulic treatment assembly. 
       
    
    
     DETAILED DESCRIPTION 
       [0019]    Embodiments are described with reference to certain multi-stage downhole hydraulic applications. In particular, downhole isolating and stimulation applications are described. However, a variety of different downhole hydraulic applications may make use of different embodiments of a hydraulic treatment assembly as detailed herein. For example, while deployment of a mechanical packer, perforating and other stimulation techniques are employed, any number of additional or alternative downhole hydraulic applications such as water jet cutting may also be undertaken. Regardless of the particular applications undertaken, embodiments of the downhole assembly employed will include use of a jetting tool capable of forming perforations while also being reversibly actuatable. So, for example, applications with tools uphole and downhole of the jetting tool may also be performed without requiring that the entire assembly first be removed from the well for adjustment of the jetting tool. 
         [0020]    Referring now to  FIG. 1 , a front view of an embodiment of a multi-stage hydraulic treatment assembly  100  is shown. The assembly  100  is configured for performing various downhole applications on a single trip into a well  380  such as that depicted in  FIG. 3 . In this regard, the assembly  100  is outfitted with a reversibly actuatable hydraulic jetting tool  150  with nozzles  155  capable of forming perforations  475  as depicted in  FIG. 4B . That is to say, the tool  150  may be hydraulically actuated for such an application and effectively deactivated thereafter to allow a hydraulic application through another tool such as the depicted fracturing tool  125 . By the same token, the fracturing tool  125  or another tool may also be used in advance of the jetting tool  150 . 
         [0021]    Due to the ability of the hydraulic jetting tool  150  to be effectively actuated and deactivated, the assembly  100  may be constructed with a number of different tools for use in downhole operations. So, for example, in the embodiment shown, a mechanical packer unit  175  is provided downhole of the jetting tool  150 . Similarly, the assembly  100  also accommodates the above-noted fracturing tool  125  above the jetting tool  150 . Each of the fracturing tool  125 , the packer unit  175 , and the jetting tool  150  may be used in whatever sequential order called for by downhole operations, for example, as detailed with reference to  FIGS. 4A-4C  herein. That is, concern over actuation of the jetting tool  150  leading to permanent deactivation of other tools, without removal of the assembly  100  from the well  380 , is obviated by the reversible nature of the jetting tool  150  (see  FIG. 3 ). 
         [0022]    Continuing with reference to  FIG. 1 , the assembly  100  is shown secured to coiled tubing  110  for downhole conveyance. However, in other embodiments alternative forms of hydraulic tubular conveyance, such as jointed pipe, may be utilized. 
         [0023]    Upon conveyance to a downhole destination, zonal isolation may be sought, for example, in advance of stimulation operations. Thus, the noted mechanical packer unit  175  is provided. However, by the same token, a bridge plug, slotted liner, or any number of zonal structures may be outfitted at the downhole end of the assembly  100  for deployment. In the case of the depicted mechanical packer unit  175 , a packer  185  with expandable seals  187  is provided along with a setting mechanism  190  which may be hydraulically controlled through the assembly  100 . More specifically, the setting mechanism  190  of  FIG. 1  is a hydrostatic set module with a hydraulic line  195  to the packer  185  to direct setting thereof. Actuation of the module itself may be directed hydraulically through the interior of a tubular  180  serving as a central mandrel for the entire assembly  100 . 
         [0024]    Upon isolation or other preliminary measures, perforating may take place through the jetting tool  150  as alluded to above. In the embodiment shown, the tool  150  is outfitted with four nozzles  155  which are vertically offset from one another as with a conventional embodiment. However, alternative orientations or total number of nozzles  155  may also be employed. Regardless, upon activation as detailed with respect to  FIG. 2  below, a conventional perforating fluid may be pumped internally through the coiled tubing  110 , fracturing tool  125 , tubular  180 , and eventually out the nozzles  155  to initiate perforating. 
         [0025]    Following perforating, the assembly  100  may be positioned for clean-out and/or fracturing through opened valves  127  in the fracturing tool  125 . So, for example, a fluid, such as water, may be pumped through the interior of the coiled tubing  110 , past a hydraulic sub  120  of the fracturing tool  125  and out the opened valves  127  for clean-out of debris. Note that the pumping of water in this manner may take place at an increased rate as compared to perforating through the jetting tool  150 . However, the larger size orifices of the valves  127  as compared to the jetting nozzles  155  effectively deactivates the jetting tool  150  as described further below. Additionally, a conventional 20/40, 100 mesh fracturing sand, fibers, and other constituents may be added to the fluid at surface, perhaps along with further modification of pump rate. In this manner, a transition from a clean-out application to a fracturing application may be made via the same fracturing tool  125 . 
         [0026]    With added reference to  FIG. 3  and as alluded to above, the move from one application to the next is achieved without removal of the entire assembly  100  from the well  380  in spite of an intervening use of the hydraulic jetting tool  150 . That is to say, isolation may precede perforating with the tool  150 , and clean-out and/or fracturing may take place thereafter without the need to remove the assembly  100  for deactivation of the tool  150 . As indicated, this is possible due to the reversible nature of the tool  150  as described below. 
         [0027]    Referring now to  FIG. 2 , side cross-sectional view of the hydraulic jetting tool  150  is shown revealing its reversible nature. That is, as opposed to actuation by way of a ball hydraulically delivered to a seal below the jetting nozzles  155 ,  255 , an internal hydraulic mandrel  201  is provided. This mandrel  201  is equipped with openings  260 ,  265  which may be reversibly aligned with the noted nozzles  155 ,  255  for their actuation and deactivation as the case may be. That is to say, with the openings  260 ,  265  out of alignment with the nozzles  155 ,  255 , a hydraulic application may take place below the tool  150 , as evidenced by the pass through of fluid flow  200 . Subsequent alignment of the openings  260 ,  265  with the nozzles  155 ,  255  may allow for jetting (e.g. perforating) through the nozzles  155 ,  255 . Indeed, subsequent lower pressure hydraulic applications above the tool  150  may take place, even while maintaining the noted alignment. Such is the case with a clean-out or fracturing application through the fracturing tool  125  of  FIG. 1  as noted above and detailed further below. 
         [0028]    Continuing with reference to  FIG. 2 , a fluid flow  200  is shown passing through the entire tool  150  without actuation of the nozzles  155 ,  255 . However, a hydraulically responsive orifice head  210  is provided which is biasingly coupled to the noted mandrel  201  as governed through a spring  220 . Thus, the orifice head  210  and spring  220  may be configured for shifting of the mandrel  201  upon introduction of a given flow rate. So, for example, where a flow rate of less than about 2 barrels per minute (BPM) is pumped through the tool  150 , the mandrel  201  may be left in the nozzle closed alignment as shown. However, when a flow rate exceeding 2 BPM is introduced, the head  210  and spring  220  may move downhole, shifting the mandrel  201  into nozzle open alignment as described below. 
         [0029]    As indicated, a nozzle open alignment of the mandrel openings  260 ,  265  with the nozzles  155 ,  255 , takes place as the mandrel  201  shifts downhole. More specifically, as the mandrel  201  shifts downhole, the uphole openings  260  of the mandrel  201  are moved into alignment with an uphole chamber  272  defined by uphole seals  282 ,  284 . This chamber  272  in turn, is in fluid communication with the uphole nozzles  155 , thereby allowing for jet perforating therethrough. Similarly, the downhole openings  265  are simultaneously moved from alignment with an isolated central chamber  274  and into alignment with a downhole chamber  276  defined by downhole seals  286 ,  288 . Thus, with the downhole chamber  276  in fluid communication with the downhole nozzles  255 , jet perforating may also take place therethrough. 
         [0030]    It is worth noting that the central chamber  274 , defined by both uphole  284  and downhole  286  seals, is provided so that while in the nozzle closed position, the downhole openings  265  remain sealed off from possible communication with the downhole nozzles  255 . Additionally, also note that with a sufficiently low flow rate, the flow  200  is allowed to pass through the tool  150  and a blank orifice  290  thereof, perhaps to hydraulically direct further downhole applications. However, by the same token, even once the open nozzle position is achieved, higher flow rate applications above and below the tool  150  may nevertheless take place. For example, higher flow rate, lower pressure applications such as a 5-6 BPM clean-out, or perhaps packer setting or other applications may take place. That is, due to lower pressures involved, no more than minimal fluid leakage would take place through the nozzles  155 ,  255  without affect on the higher flow rate applications. 
         [0031]    Referring now to  FIG. 3 , an overview of an oilfield  300  is depicted with a well  380  accommodating the overall treatment assembly  100  of  FIG. 1  therein. In the embodiment shown, the well  380  traverses various formation layers  390 ,  395  and is outfitted with a casing  385  throughout, even into a lateral leg region. However, in alternate configurations, this region may remain open-hole in nature. Regardless, coiled tubing  110  is employed for conveyance of the assembly  100  through the well  380 , including positioning of a mechanical packer  175  within the noted lateral leg region. Thus, the setting mechanism  190  may ultimately be employed to direct isolation of this region with the packer  175  (see also  FIG. 4A ). However, as indicated above, further downhole activity, such as clean-out below the packer  175  by way of the assembly  100  may precede packer setting. 
         [0032]    Continuing with reference to  FIG. 3 , the assembly  100  includes tubular structure  180  for joining the packer  175  to the jetting tool  150 . Indeed, a detachable coupling  380  is shown disposed therebetween. Thus, once the packer  175  is set, the tool  150  and the remainder of the assembly  100  may be detached from the set packer  175  and utilized elsewhere in the well  380 . In the embodiment shown, perforating via the jetting tool  150  is to take place immediately above the packer  175  and into the lower formation layer  395  as described above. However, with the tool  150  detached from the packer  175 , other formation locations may also be targeted. 
         [0033]    Subsequent clean-out, fracturing or other stimulation applications may take place through the fracturing tool  125 , with fluid, debris and other material produced through a production line  375  at surface. Indeed, at the oilfield  300  a host of surface equipment  350  is provided for directing and driving the use of the entire treatment assembly  100 . As shown, a mobile coiled tubing truck  330  is delivered to the well site accommodating a coiled tubing reel  340  along with a control unit  355  for directing the deployment of the assembly  100  as well as hydraulic applications therethrough. A pump  345  is also provided for maintaining flow through the coiled tubing  110  as well as for introducing application specific constituents such as proppant, fibers and/or sand as needed. 
         [0034]    In the embodiment shown, the truck  330  is outfitted with a mobile rig  360  which accommodates a conventional gooseneck injector  365 . The injector  365  is configured for driving the coiled tubing  110  and assembly  100  through valve and pressure control equipment  370 , often referred to as a “Christmas tree”. Thus, positioning is provided for the carrying out of downhole hydraulic applications as detailed further below. Further, as noted above, separate multi-stage operations may proceed without the need to remove and adjust the assembly  100 , particularly the jetting tool  150  between different hydraulic applications. 
         [0035]    Referring now to  FIGS. 4A-4C , sequential multi-stage stimulation operations in the well  380  with the treatment assembly  100  of  FIG. 3  as alluded to above are shown in greater detail. More specifically,  FIG. 4A  reveals the setting of the mechanical packer  175  in the horizontal region of the well  380 . This is followed by the perforating of the well  380  in a vertical region with the jetting tool  150  as depicted in  FIG. 4B . Subsequently, a clean-out of the perforations  475  may be performed by the fracturing tool  125  as depicted in  FIG. 4C . Of course, additional stimulation through the fracturing tool  125  is also possible, such as acidizing or actual fracturing (see the frac-matrix support  500 , evident in  FIG. 5 ). 
         [0036]    With specific reference to  FIG. 4A , an enlarged depiction of a horizontal section of the well  380  is shown with the noted mechanical packer  175  set therein. That is, in contrast to the depiction of  FIG. 3 , the seals  187  are fully expanded into engagement with the casing  385  so as to provide isolation below the packer  175 . As indicated above, this may be achieved by way of hydraulic actuation of a setting mechanism  190 , which in turn sets the packer  175 . In the embodiment shown, the setting mechanism  190  may be a hydrostatic set module linked to the packer  175  through a hydraulic line  195  to drive the setting. However, in other embodiments, the mechanism  190  may be activated through a conventional ‘ball drop’ or other suitable technique. 
         [0037]    Continuing with reference to  FIG. 4A , note the presence of a terminal nozzle  400  located below the packer  175 . In one embodiment, such a nozzle may be employed for clean-out in advance of packer setting. That is, packer setting via the setting mechanism  190  (or perforating through the jetting tool  150  (see  FIG. 4B )) may be responsive to certain hydraulic profiles and/or pump rates. However, different hydraulic profiles and/or pump rates may be utilized for clean-outs. So, for example, pump rates outside of a 1-3 BPM rate or so may be utilized for clean-outs, whereas such a 1-3 BPM rate may be utilized for perforating as described above. Meanwhile, a ball-drop technique, sonic profile or other suitable hydraulic actuation means may be utilized for packer setting via the mechanism  190  or other alternative downhole application. 
         [0038]    Referring now to  FIG. 4B , an enlarged depiction of a vertical section of the well  380  is shown with the noted perforations  475  formed via the perforating tool  150 . As indicated, the perforations  475  may be formed by way of pumping a flow of 1-3 BPM through the tool  150  to actuate the nozzles  155 . Conventional perforating sand and other material may be pumped along with fluid flow as directed from surface so as to form the perforations  475  through the casing  385  and into the formation  395 . The effectiveness of the perforating may be enhanced due to the zonal isolation provided by the set packer  175  therebelow (see  FIG. 4A ). 
         [0039]    While effective perforations  475  may serve as an aid to production from the formation  395 , a certain amount of debris  480  may remain and serve as a hindrance to recovery. Thus, as depicted in  FIG. 4C , further clean-out may be in order.  FIG. 4C  reveals an enlarged view of a clean-out application by the above detailed fracturing tool  125 . In one embodiment, the tool  125  may be a conventional multi-cycle circulating valve. Regardless, a clean-out takes place, generally at a pump rate of between about 4-7 BPM, debris  480  and other fluid may be flowed uphole and eventually produced through the production line  375  at surface (see  FIG. 3 ). Once more, as noted above, this clean-out may be initiated through the fracturing tool  125  following the perforating with the jetting tool  150 , without any need for removal of the jetting tool  150  from the well  380 . 
         [0040]    Referring now to  FIG. 5 , an enlarged view of a perforation  475  is depicted, taken from  5 - 5  of  FIG. 4C . In this view, frac-matrix support  500  is shown following a fracturing application with the fracturing tool  125  of  FIG. 4C . That is, after a clean-out via the tool  125  as noted above, fibers, proppant and other constituents may be added to the flow and/or the flow rate adjusted for fracturing to proceed. The end result, represented in the perforation  475  of  FIG. 5 , may be a matrix support  500  of structure to help hold open and enhance hydrocarbon recovery from the perforation  475  and into the main body of the well  380  for production to surface. 
         [0041]    Referring now to  FIG. 6 , a flow-chart summarizing an embodiment of employing a multi-stage downhole hydraulic stimulation assembly is depicted. As indicated, the assembly is deployed into the well and an initial actuation may take place such as the hydraulic setting of a mechanical packer (see  620 ,  640 ). The deployment may take place over coiled tubing, jointed pipe or other appropriate hydraulic tubular conveyance. Additionally, the hydraulic actuation may take place via conventional ball-drop, wireless acoustics or sonic signaling, the particular mode dependent upon the type of setting mechanism utilized. Of course, the tool may also be a downhole tool other than a mechanical packer, bridge plug or other isolating mechanism. Furthermore, a clean-out application as indicated at  680  may take place before, after, or in lieu of the initial actuation of this downhole tool. 
         [0042]    Regardless of initial stimulation measures, subsequent stages may include the performing of a perforating application via a jetting tool as indicated at  660 . This perforating may take place at a comparatively high pressure but low BPM flow rate. Perhaps most notably, however, is the fact that following perforating, the entire assembly may be maintained in the well as indicated at  680  regardless of the particular next stage hydraulic application to be undertaken (e.g. such as a higher BPM clean-out). 
         [0043]    Embodiments described hereinabove include a downhole treatment and/or stimulation assembly that may be utilized for multi-stage applications in a given well zone without requiring that the assembly be removed between stages of the applications. More specifically, where one stage includes perforating, the assembly need not be removed for adjustment of the perforating tool before or after the perforating. Rather, the application stage to be undertaken before or after the perforating may be undertaken without compromise even in the absence of removal of the perforating tool to surface. 
         [0044]    The preceding description has been presented with reference to presently preferred embodiments. Persons skilled in the art and technology to which these embodiments pertain will appreciate that alterations and changes in the described structures and methods of operation may be practiced without meaningfully departing from the principle, and scope of these embodiments. For example, embodiments depicted herein reveal a perforating tool which is reversibly actuatable by way of a position shifting internal hydraulic mandrel. However, other techniques may be utilized to allow for reversible actuation of the perforating tool. Such alternatives may include use of ball actuation and recovery through a flow back technique that avoids the need to remove the tool from the well for deactivation. Furthermore, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.