Abstract:
A downhole hydraulic tool employing multiple nozzles in a selectable fashion from an oilfield surface. At least one of the nozzles of the tool is equipped with a burst disk such that fluid pressure directed from the surface may be utilized in activating the nozzle. The pressure may be driven to exceed a predetermined level for sake of the activating by way of sealing off access to other nozzle(s) therebelow, for example, by way of standard ball drop techniques. Thus, nozzle selectivity may be taken advantage of when a first nozzle wears out without requiring time consuming removal of the tool from the well for sake of remedial repairs or replacement.

Description:
BACKGROUND 
     Exploring, drilling and completing hydrocarbon 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, today&#39;s hydrocarbon wells often include deviated or horizontal sections aimed at targeting particular underground reserves. Indeed, at targeted formation locations, it is quite common for a host of lateral legs and perforations to stem from the main wellbore of the well toward a hydrocarbon reservoir into the surrounding formation. 
     The above described perforations are formed and effectively completed by a series of applications that begin with perforating the well wall. So, for example, a casing defining the well may be perforated by a series of projectiles directed at a targeted location by way of a perforating gun. The gun itself may be equipped with conventional charges for powering the projectiles, with the application itself directed over standard wireline running from the oilfield surface. 
     Perforating in this manner generally takes place in a zone by zone fashion. That is, for sake of effective management, production regions are divided into 20 to 40 or more zones, often ranging from 3 feet to 50 feet or so apiece. Thus, over the course of perforating a well, one zone is generally perforated, followed by another, and so on. Once more, fully developing perforations for sake of enhancing recovery, requires more than the initial perforating via the perforating gun. Rather, follow-on fracturing, or “fracing”, and cleanout applications are also employed. The fracturing involves pumping a fracturing fluid with solid proppant particulate to the perforated locations to provide a degree of channel stabilization. Subsequently, a cleanout application may be employed to remove excess debris and particulate following the perforating and fracturing. 
     Unfortunately, the step by step process of perforating, fracturing and cleanout is performed on a zone by zone basis. So, for example, following the perforating, the gun may be removed and other fracturing and cleanout equipment lowered into position for these subsequent applications. Afterwards, the entire process of delivering and removing the various pieces of equipment may be repeated for each and every zone. In fact, each zone may even be isolated in advance of perforating and fracturing, thus adding further layers of complexity and time to the overall process. 
     In order to streamline the above described process of perforating and fracturing various downhole zones, coiled tubing perforating equipment may be utilized. More specifically, a hydraulically driven coiled tubing assembly may be outfitted with a jetting tool and other features capable of performing each of the various perforating, fracturing and cleanout functions. That is, the coiled tubing may be advanced to the downhole perforating location and the jetting tool employed to create the above described perforations. However, rather than remove the coiled tubing, it may be left in place as a fluid-based fracturing application is directed through the coiled tubing (or adjacent to it within an annulus formed between the coiled tubing and the wellbore) to the recently perforated zone. Indeed, the coiled tubing may remain in place to serve as the platform for a subsequent circulating cleanout application. 
     In theory, routing each of the various applications through the same bottom hole assembly (BHA) at the end of the coiled tubing would save a tremendous amount of time in terms of trips into the well. That is, after one zone is finished, the coiled tubing may be moved to the next zone and the same applications repeated through the same BHA without the need to return to the oilfield surface. 
     Unfortunately, the ability to fully take advantage of the coiled tubing BHA for the different applications noted above is limited by the nozzles of the jetting tool. As noted above, the BHA is outfitted with a jetting tool which utilizes nozzles in achieving the perforating at each zone. However, even the most robust of nozzles is likely to be effective for no more than about 5 to 10 perforating applications. This is due to the naturally occurring erosion which tends to enlarge the diameter of the nozzles over repeated use. As a result, after perforating and fracturing 5 to 10 zones or so, the entire coiled tubing is removed from the well so that the nozzles and/or the entire jetting tool of the BHA may be replaced. The assembly is then re-deployed for use in subsequent zones, with this process repeated until all of the perhaps 40 or more zones are fully perforated, fractured and cleaned out. Thus, the ability to attain the full advantage leaving the coiled tubing downhole throughout the perforating and fracturing of the entire well remains elusive. 
     In some circumstances, efforts may be undertaken to extend the effective life of the nozzle without removing the BHA. For example, as later zones are perforated, operators at the oilfield surface may increase pressure and flow rates in an attempt to compensate for increasing diameter of the eroding nozzles. However, such efforts are unlikely to extend nozzle life beyond an additional perforating application or two. Thus, as a practical matter, the operator is still likely to remove the entire BHA on multiple occasions, adding significant time and expense to overall perforating and fracturing operations. 
     SUMMARY 
     A nozzle selective perforating jet assembly is provided with multiple nozzles. A first jetting nozzle may be situated at a given location of the assembly for directing a first perforating application. Further, another nozzle may be positioned at another location for a subsequent perforating application. Once more, a burst disk may be incorporated into the other nozzle for the subsequent application so as to occlude fluid access thereto when pressure in the assembly is below a predetermined level. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a front view of an embodiment of a nozzle selective perforating jet assembly. 
         FIG. 2  is an overview of an oilfield having a well with the nozzle selective perforating jet assembly of  FIG. 1  disposed therein. 
         FIG. 3A  is an enlarged view of a jetting tool of the assembly of  FIG. 1  utilizing burst disk nozzles to form perforations in the well of  FIG. 2 . 
         FIG. 3B  is an enlarged view of a perforation of  FIG. 3A  following a fracturing application with the assembly. 
         FIG. 3C  is an enlarged view of the assembly of  FIG. 3A  during a cleanout application in the well. 
         FIG. 4A  is a perspective view of a first burst disk nozzle of the jetting tool following significant perforating application wear. 
         FIG. 4B  is a perspective view of a second burst disk nozzle of the jetting tool prior to use in a perforating application. 
         FIG. 5A  is a side cross-sectional view of the jetting tool at the outset of downhole perforating applications. 
         FIG. 5B  is a side cross-sectional view of the tool of  FIG. 5A  employing subsequent burst disk nozzle selection following wear-out of prior nozzles. 
         FIG. 6  is a flow-chart summarizing an embodiment of employing a nozzle selective perforating jet assembly in a well. 
     
    
    
     DETAILED DESCRIPTION 
     Embodiments are described with reference to certain downhole applications conveyed by way of coiled tubing. For example, coiled tubing driven perforating, fracturing and cleanout operations are detailed within a cased well. However, other types of applications, tools and environments may be applicable. For example, embodiments of jetting tools directed at open hole environments or liners of lateral legs may be applicable. Additionally, conveyance for sake of perforating may be achieved by way of drill pipe or other tubular deployment. Regardless, the jetting tool includes multiple nozzles which may be selectively actuated via burst disk mechanics depending upon internal sealing and hydraulic pressure directed through the tool. 
     Referring now to  FIG. 1 , a front view of an embodiment of a nozzle selective perforating jet assembly  100  is shown. The assembly  100  includes a jetting tool  101  outfitted with pairs of nozzles  120 ,  140 . With reference to a given nozzle set (e.g.  140 ), the nozzles thereof appear roughly opposite one another at a particular radial depth location of the tool  101 . However, in other embodiments such nozzles  140  may be staggered relative one another in terms of depth location or even located at different radial positions of the tool  101  other than 180° directly opposite one another. 
     The nozzles  120 ,  140  of the jetting tool  101  are configured to guide perforating as detailed hereinbelow (see  FIG. 3A ). This application involves driving an abrasive silica or sand-based slurry through coiled tubing  110  of the assembly  100  and ultimately directed through the nozzles  120 ,  140 . More specifically regarding the embodiments depicted, however, the nozzles  120 ,  140  may be selectively employed through the use of burst disks  400  (see  FIG. 4B ). So, for example, with added reference to  FIG. 4 , in one embodiment, the uphole nozzles  140  may be outfitted with burst disks  400  to prevent jetting therethrough until a predetermined pressure has been attained. That is, an operator may initially direct perforating through the downhole nozzles  120  for a period of uses. However, once a determination is made that such nozzles  120  may be damaged, for example, through natural wear, they may be hydraulically shut off by way of a conventional ball drop or other suitable technique. As such, pressure within the tool  100  may then be driven up until burst disks  400  of the uphole nozzles  140  are ruptured, at which time, these nozzles  140  may then be utilized for subsequent perforating. 
     The above described technique of nozzle selective perforating allows the operator to use different sets of nozzles  120 ,  140  in succession. Indeed, in other embodiments, nozzles at more than two depth locations may be successively employed through the use of burst disks  400  as shown in  FIG. 4B . Thus, with added reference to  FIG. 2 , an operator at an oilfield  200  need not pull the entire assembly  100  out of the well  280  each time a nozzle or nozzle set  120  wears out. Rather, the operator may simply shut off the worn out nozzles  120  and move to the next uphole set via burst disk actuation as noted above and detailed further below. 
     Continuing with reference to  FIG. 1 , the assembly  100  depicted includes a variety of additional features useful in operating a perforating jetting tool  101 . For example, an anchor segment  175  may be provided for setting the assembly  100  in advance of performing tasks such as the noted perforating via the tool  101 . In the embodiment shown, a compression set anchor is utilized, though other setting mechanisms may be employed. Furthermore, where oriented perforating is desired, such as within a lateral or substantially horizontal well section, swivel  155  and eccentric weighted  160  segments may be provided. Additionally, in the embodiment shown, a reverse circulation segment  150  is depicted which may be utilized in follow-on clean-out applications as detailed hereinbelow. 
     In addition to the above noted features, multi-cycle, coupling, isolation and other standard bottom hole assembly features may be incorporated into the assembly  100 . Once more, the features may be provided in multiple and rearranged configurations. For example, multiple isolation devices may be utilized both above and below the jetting tool  101  or alternatively a single isolation device positioned above or below the tool  101 . 
     Referring now to  FIG. 2 , an overview of an oilfield  200  is depicted with a well  280  accommodating the nozzle selective perforating jet assembly  100  of  FIG. 1  therein. In this depiction, the assembly  100  is shown advancing into a well  280  and traversing various formation layers  290 ,  295  prior to perforation. For example, as detailed further below with respect to  FIGS. 3A-3C , the tool  101  of the assembly  100  may be positioned adjacent casing  285  at one depth or another for sake of perforating and other stimulation efforts. Indeed, the well  280  may be sectioned off into various 3-50 foot or so ‘zones’ adjacent the different layers  290 ,  295 , with each zone slated to undergo a series of applications as detailed with reference to  FIGS. 3A-3C . Once more, the ability to leave the assembly  100  and tool  101  downhole for a maximum of different perforating applications at different zones may be of significant advantage. More specifically, with reference to  FIG. 2 , the tool  101  need not be pulled out of the well  280  and disassembled past various equipment described below each time a set of nozzles wears out. Rather, shut off of worn out nozzles and burst disk activation of unused nozzles may be utilized as detailed above to significant cost and time saving advantage. 
     In the embodiment of  FIG. 2 , the assembly  100  is conveyed by way of coiled tubing  110  drawn from a reel  230  at the oilfield surface  200 . More specifically, a coiled tubing truck  220  is positioned adjacent the well  280  for sake of providing the reel  230  along with a pump  225 , control unit  227 , mobile rig  240  and other equipment. The rig  240  supports the transition of coiled tubing  110  from the reel  230  and through a gooseneck injector  250  and standard pressure control equipment  275  at the well head  260 . A variety of hydraulic conveyances may be utilized in positioning the assembly  100  and jetting tool  101  in light of the hydraulic influx of jetting fluids into the well  280  and subsequent cleanout. However, the forcible injective advancement of coiled tubing  110  may be particularly useful in circumstances where the well  280  is of extended reach or includes substantially horizontal, lateral, or other tortuous well sections. 
     Referring now to  FIGS. 3A-3C , enlarged views of the jetting tool  101 , and/or perforations  300  formed thereby into the adjacent formation  290 , are depicted. More specifically,  FIG. 3A  shows the tool  101  of  FIG. 1  utilizing nozzles  120  to form the noted perforations  300  in the well  280  of  FIG. 2 . Subsequently, the results of a fracturing application, with proppant, shown as proppant supported fibrous network  350 , are depicted at the enlarged view of the perforation  300  of  FIG. 3B . Finally, a cleanout application directed through the reverse circulation segment  150  of the tool  101  is shown at  FIG. 3C . Notably, each of the referenced applications regarding  FIGS. 3A-3C  may be run through the tool  101  without the need for its intervening removal to the oilfield surface  200  (see  FIG. 2 ). 
     Referring specifically now to  FIG. 3A , the tool  101  may be positioned as indicated. With position confirmation via the control unit  227  of  FIG. 2 , the assembly  100  may be directed to anchor in place utilizing the anchor segment  175  of  FIG. 1 . In one embodiment, anchoring may be hydraulically achieved with a monitored pressure indicative of achieving an anchored setting. By the same token, in embodiments where zonal isolation is to be employed, isolating devices at either side of the tool  101  may also be hydraulically actuated. In either case, abrasive jetting through the initial set of nozzles  120  may now ensue so as to form the depicted perforations  300 . Depending on the pressures utilized and a host of other factors, the perforations  300  may reach between a couple of inches to a foot or more into the formation  290 . 
     In one embodiment, even the initial set of nozzles  120  are of a burst disk variety. Thus, pressure utilized in the jetting application depicted is sufficient for bursting disks incorporated into these nozzles  120  so as to initiate perforating. For example, in one embodiment, a 2,000-3,000 PSI differential is utilized in jetting through these nozzles  120 . As such, where they are equipped with burst disks, a pressure rating of below about 2,000 PSI may be utilized for these particular disks. Further, in circumstances where the burst disk for one of the pair of nozzles  120  breaks but the other does not, flow rate may be increased so as to overrun the jetting of the open nozzle  120  and allow the other disk to break for opening of the other nozzle  120 . So long as pressure is kept below the higher pressure rating of disks associated with uphole nozzles  140 , this technique may be utilized to ensure that both downhole nozzles  120  are opened. Of course, as noted above and detailed further below, the backup or uphole nozzles  140  are also made available once the initial downhole nozzles  120  begin to show wear from the initial described perforating. 
     Referring specifically now to  FIG. 3B , an enlarged view of a perforation  300  of  FIG. 3A  is shown following a fracturing application with the assembly  100  of  FIGS. 1 and 2 . More specifically, a proppant supported fibrous matrix  350  is shown disbursed throughout the perforation  300  so as to support subsequent hydrocarbon recovery therefrom. The fracturing application may be similar to the noted perforation. However, the fracturing fluid may be delivered at lower pressures and higher volumes, with the fluid emerging from ports other than the nozzles  120 ,  140 . Regardless, following perforating and fracture fluid delivery, debris  375  in the area may then be cleaned out as depicted in  FIG. 3C . More specifically, a conventional cleanout may be run through the reverse circulation segment  150  as noted above. Thus, the assembly  100  may be repositioned with a subsequent well zone undergoing a similar set of perforating, fracturing and cleanout procedures. 
     Referring now to  FIGS. 4A and 4B , with added reference to  FIG. 1 , perspective views of nozzles  120 ,  140  are depicted. More specifically, the downhole nozzle  120  is depicted following a series of perforation applications which have inflicted a certain natural degree of damage  401 . The uphole nozzle  140 , on the other hand, remains in-tact and in an unused condition as detailed further below. Such nozzles  120 ,  140  define a channel  410 , generally ranging between about 0.10 and 0.25 inches in diameter. Further, both nozzles  120 ,  140  are equipped with an exposed cover  420  that transitions into a main body  475  and seal  450  coupled to a cylinder housing  430  that surrounds the nozzle channel  410 . However, the uphole nozzle  140  is also outfitted with a burst disk  400  as detailed further below. 
     Continuing with specific reference to  FIG. 4A , as sand-based perforating fluids are jetted out of the nozzle channel  410 , erosion begins to take place at defining surfaces of this channel  410  and the nozzle cover  420 . Indeed, even where durable carbide-based materials are utilized, such erosion may be expected after some period of use. Further, once begun, the degree of erosion may increase exponentially with each successive perforating application via the nozzle  120 . Ultimately, the effectiveness of the nozzle  120  for sake of perforating may be reduced or negligible. However, as noted above, the unused uphole nozzle  140  remains incorporated with the tool  101  (of  FIG. 1 ). 
     Referring now to  FIG. 4B , the downhole nozzle  140  is equipped with a burst disk  400  as noted above. So, for example, the interior of this nozzle  140  is not exposed to jetting fluids. Thus, perforating-based wear at its interior channel or cover surface  420  is unseen as in the case of the downhole nozzle  120  (e.g. at  401 ). By the same token, however, this nozzle  140  is unavailable for use in abrasive jetting for sake of perforating as detailed hereinabove. Nevertheless, as detailed below, once the downhole nozzle  120  is rendered ineffective as shown in  FIG. 4A , it may be closed off and the burst disk  400  of the uphole nozzle  140  ruptured, such that a new nozzle  140  is available for operations. More specifically, the disk  400  may be of a predetermined pressure rating. Therefore, rupturing of the disk  400  in this manner may be a matter of applying a correspondingly predetermined pressure through the tool  101  of  FIG. 1 . As such, the need to remove the entire assembly  100  of  FIGS. 1 and 2  in order to redress an inoperable nozzle is obviated, thereby saving considerable downhole time and expense. 
     Referring now to  FIGS. 5A and 5B , side cross-sectional views of the jetting tool  101  of  FIGS. 1 and 2  are depicted. More specifically,  FIG. 5A  is a view of the tool  101  at the outset of perforating applications where fluid access to downhole nozzles  420  is available for sake of abrasive jetting.  FIG. 5B , on the other hand reveals closed off fluid access to these nozzles  420  via a pressure technique that also results in the burst disk opening of the uphole nozzles  420 . 
     With more direct reference to  FIG. 5A , the tool  101  includes a central tool channel  580  that is in fluid communication with coiled tubing  110  as depicted in  FIGS. 1 and 2 . In the embodiment shown, a ball projectile  570  may be introduced to the channel  580  and pumped to an initial valve seat  567  as a conventional manner by which to initiate perforating through initial nozzles  515  at an initial depth  510 . By the same token, depending on pressure through the channel  580  perforating at the downhole depth  520  via downhole nozzles  120  may also ensue. 
     Continuing with reference to  FIG. 5A , uphole  140  and further uphole  555  nozzles may remain sealed off via burst disks  400  as described hereinabove at  FIG. 4B . For example, these uphole nozzles  140 ,  555  may be outfitted with disks  400  having a rating that exceeds 3,000 PSI whereas the perforating application taking place through the downhole  120  and initial  515  nozzles occurs at a differential of below about 2,500 PSI. 
     With specific reference now to  FIG. 5B , the above noted downhole  120  and initial  515  nozzles may wear out over the course of successive perforating applications as detailed above. Therefore, a subsequent projectile ball  575  of greater diameter than the first  570  may be introduced into the channel  580 . As shown, the ball  575  is sized to sealably encounter a sealing location of a subsequent valve seat  565  located between the uphole  140  and downhole  120  nozzles. Thus, once the ball  575  is sealingly engaged with the seat  565 , the damaged valves  120 ,  515  therebelow are effectively shut off. Once more, flow may be directed through the channel  580  such that a pressure exceeding the predetermined amount, 3,000 PSI in the example noted above, may be produced. As such, the disk  400  of the uphole nozzle  140  may be burst open and utilized in continuing perforating operations. In this manner, a new nozzle  140  is made available to the tool  101  without the need for tool removal from the well  280  during ongoing operations (see  FIG. 2 ). Once more, the providing of a new nozzle  140  is done in a manner that does not require movement or shifting of downhole tool components. This may be of particular advantage where more abrasive perforating fluids are utilized which may tend to inflict wear and sticking on such components. 
     The above detailed technique for equipping and utilizing successive sets of nozzles  120 ,  140  may be continued to any practical number of depths  510 ,  520 ,  540 ,  550 . For example, as shown in  FIGS. 5A and 5B , a further uphole nozzle  555  is shown which may be burst disk protected to a pressure of more than about 4,000 PSI. Furthermore, where multiple burst disk nozzles  140  are positioned at roughly the same depth location for simultaneous use, the bursting of multiple disks  400  may be operator ensured by increasing flow rate through the channel  580  as necessary. For example, where pressure feedback at surface is indicative of a single burst where multiple bursts are called for at a given location, flow rate may be increased as a manner of overrunning burst capacity of the other nozzle&#39;s disk. 
     Referring now to  FIG. 6 , a flowchart is depicted summarizing an embodiment of employing a nozzle selective perforating jet assembly in a well. More specifically upon deployment into the well as indicated at  605 , an initial series of perforating applications may be run as indicated at  620 . However, upon wear at initial nozzles, they may be hydraulically sealed off (see  635 ). Indeed, in embodiments hereinabove, the same techniques for closing off the initial nozzle(s) may support increasing pressure to burst a disk as noted at  650 . Thus, subsequent nozzle(s) may be exposed for subsequent perforating as indicated at  665 . In addition to leaving the tool in the well during the transition from a worn set of nozzles to a fresh set, as indicated at  680  and  695 , fracturing, cleanout and other applications may also ensue via the same assembly accommodating the tool without requirement of its removal from the well. 
     Embodiments described hereinabove allow for jetting tool perforating applications in a manner that substantially extends the life of the tool. More specifically, the tool need not be removed and repaired after every 5 to 10 jetting perforating applications. Indeed, any practical number of perforating applications may be directed through the same jetting tool without requirement of intervening remedial action. Such is limited only by the design constraints employed such as varying burst pressure ratings, tool channel and projectile ball diameters and other factors. Regardless, operators need not attempt to ineffectively drive pressures up to extend the nozzle life but rather are provided with a viable technique for leaving the tool downhole while moving on from a worn nozzle to a fresh one for subsequent perforating. 
     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, the burst disk concepts described herein may be employed in a contingency fashion so as to allow operator directed nozzle use in circumstances apart from perforating. These circumstances may include unsticking a tool, introducing annular circulation or dealing with a variety of other emergent circumstances. 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.