Patent Publication Number: US-2013248192-A1

Title: Multizone and zone-by-zone abrasive jetting tools and methods for fracturing subterranean formations

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of U.S. Provisional Patent application Ser. No. 61/614,076, filed Mar. 22, 2012, the entirety of which is incorporated herein by reference. 
    
    
     FIELD 
     Embodiments disclosed herein relate to systems, tools and methods for jet perforating a tubular extending into a subterranean formation, the tool releasably sealing an annulus about the tubular for controllably directing fluid for forming the perforations and for fracturing the formation therethrough. 
     BACKGROUND 
     Horizontal wellbores in a formation are often lined with a primary casing along the vertical portion and heel, the primary casing being cemented therein. An open wellbore portion extends horizontally from the heel along the formation through one or more zones of interest. Completion tools can be run into the openhole portion of the wellbore for fracturing the wellbore to enhance production therefrom. 
     It is also known to run in a production liner or secondary casing through the primary casing and along the open wellbore portion. The liner or secondary casing can be left uncemented or can be cemented in the wellbore. The liner is thereafter perforated at a plurality of locations spaced therealong and corresponding to the zones of interest to create flowpaths therethrough to permit fluids, such as fracturing fluids, to reach the formation therebeyond. 
     One method is to fit a completion string with a plurality of conventional tools, such as shown in  FIG. 1A , one tool per zone of interest, and run the completion string into the liner, aligning the tools with the zones. A treatment annulus is formed between the completion string and liner. Each conventional tool comprises a sub having a jet housing with a bore contiguous with the completion string. The jet housing is fit with a plurality of jet ports oriented towards the wall of the liner. The jet ports are alternately blocked or opened to the bore by a sliding sleeve fit to the housing bore. The uphole end of the sleeve of each tool is sized to receive a corresponding drop ball, each successive uphole tool in the completion string having a ball seat with a successively larger diameter. 
     In operation, the completion string with jet tools is run into the liner. A first ball is dropped, shifting the sleeve of the distal, downhole-most tool open and blocking the bore of the tool below the jet ports. Abrasive fluids are pumped down the completion string to direct abrasive fluid through the opened jet ports against the liner, perforating the liner and eroding the formation therebehind. Once the perforating is complete, fracturing fluid is directed downhole which also flows through the jet ports and into the formation, fracturing the formation and directing sand or other proppent into the formation. Some circulation of clean fluid continues to remove excess fracturing sand up the annulus. Optionally, one can reverse circulate, down the annulus and up the bore to circulate the dropped ball to surface. 
     The process is repeated with a next larger ball corresponding with the diameter of the ball seat on the next uphole tool. 
     It is known that each successive fracturing process is at risk of lower efficiency as a partial flow path can develop or exist along the annulus towards a downhole previous zone. Clearly there is interest in developing tools and processes which enable more efficient and effective fracturing. 
     SUMMARY 
     Embodiments disclosed herein enable setting and maintaining a packer element, incorporated into a fluid-jetting sub, in a set position using a fluid pressure in the completion tubing on which the sub is conveyed. Pressure in the completion tubing is maintained at a higher pressure than in an annulus surrounding the sub for maintaining the packer element in the set position. In embodiments the packer element is an inflatable element and in other embodiments the packer element is a compressible packer element. 
     In one broad aspect, a fluid-jetting sub is deployable into a wellbore on a completion string and forming an annulus therebetween, for use in perforating and fracturing a subterranean formation. The sub comprises: a tubular housing adapted for connection to the completion string and having a tool bore formed therethrough being contiguous with a bore of the completion string. A plurality of jet ports extend substantially radially through the tubular housing. A packer element is formed circumferentially about the housing downhole of the plurality of jet ports and is adapted to seal the annulus when actuated to a set position. A fluid block is formed in the bore of the housing downhole of at least the plurality of jet ports for at least temporarily blocking a flow of fluid through the tool bore therebelow. When the fluid is at least temporarily blocked, the fluid in the tool bore is caused to exit the plurality of jet ports for delivering fluid therethrough for perforating and fracturing the formation; and operatively engages the packer element for actuating the packer element to the set position. 
     In another broad aspect, a completion tool is deployable into a wellbore on a completion string and forms an annulus therebetween for use in perforating and fracturing a subterranean formation. The tool comprises: one or more fluid-jet subs incorporated in the completion string. Each of the one or more fluid-jet subs has a tubular housing connectable within the completion string and having a tool bore formed therethrough being contiguous with a bore of the completion string. A plurality of jet ports extend substantially radially through the tubular housing. A packer element is formed circumferentially about the housing downhole of the plurality of jet ports for sealing the annulus when actuated to a set position. A fluid block is formed in the bore of the housing downhole of at least the plurality of jet ports for at least temporarily blocking a flow of fluid through the tool bore therebelow. When the fluid is at least temporarily blocked, the fluid flowing through the bores of the tubing string and the fluid-jet sub is caused to exit the plurality of jet ports for delivering fluid therethrough for perforating and fracturing the formation; and to operatively engage the packer element for actuating the packer element to the set position. 
     In an embodiment, the completion string is a jointed tubular string and the one or more fluid-jetting subs is two or more fluid-jet subs, the two or more fluid-jet subs being spaced along the jointed tubular string for positioning at zones of interest in the formation. 
     In another embodiment, the completion string is coiled tubing and the one or more fluid-jetting subs is one fluid-jetting sub, the fluid-jetting sub being positioned adjacent a distal end of the coiled tubing for positioning at zones of interest in the formation. 
     In yet another broad aspect, a method for completion of a wellbore comprises: incorporating one or more fluid jetting subs into a completion tubing string deployed into a wellbore and forming an annulus therebetween. Each of the one or more fluid jetting subs has a housing having a bore formed therethrough contiguous with a bore of the completion string. One or more jet ports extending radially through the housing and a packer element is formed about the housing therebelow. The flow of fluid through the tool bore is at least temporarily blocked below at least the jet ports. Fluid is flowed through the contiguous bore for increasing pressure within the tool bore to greater than outside the housing. The pressure acts to actuate the packer element to a set position and to jet fluid through the one or more jet ports for jetting perforations in at least the wellbore. The pressure is maintained in the tool bore greater than outside the housing to maintain the packer element in the set position while providing treatment fluid through the completion string or through the annulus for treating the formation through the perforations. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a sectional side view of a prior art jet sub, a plurality of which are spaced along the wellbore; 
         FIG. 2A  is a sectional side view of an embodiment of a fluid jetting sub having an one or more jet ports, an inflatable packer element therebelow and one or more packer ports for inflation of the packer element prior to actuation of the packer, the one or more jet ports and the one or more packer ports being covered by a sleeve in a closed position; 
         FIG. 2B  is a sectional side view of the inflatable fluid jetting sub of  FIG. 2A  following shifting of the sleeve to open the one or more jet ports for perforation and the one or more packer ports for actuation of the packer element; 
         FIGS. 3 to 8  are schematic illustrations of an embodiment having a plurality of fluid jetting subs according to  FIG. 2A  incorporated into and spaced apart along a completion string, 3½ inch tubing string the completion string being jointed tubing such as a 3½ inch tubing string, more particularly, 
         FIG. 3  illustrates initial steps in completing access to a subterranean formation, commencing with running in a first casing string along the vertical and heel portion of the wellbore, typically cementing the first casing therealong, with open hole along the zones of interest and running in a secondary casing string, such as 5½ inch casing, into the open hole portion for accessing the formation; 
         FIG. 4  illustrates a next step of running in the completion string for locating and spacing a plurality of the fluid-jetting subs having the inflatable packer elements along the second casing string and forming a circulation annulus therebetween; 
         FIG. 5  illustrates commencement of jet perforation and treatment at a first interval initiated by a ball drop for the downhole zone for shifting the sleeve of the first, downhole-most fluid-jetting sub to the open position for enabling abrasive jetting and setting of the inflatable packer; 
         FIG. 6A  illustrates the next step of providing a fluid flow through the tubing string to the open packer ports for inflating the packer and applying abrasive fluid to the open jet ports for jet perforating the second casing string at the downhole zone of interest, enabling fracturing of the zone through the jet ports as desired; 
         FIG. 6B  illustrates an optional intermediate step of reverse circulating down the circulation annulus to recover the previous dropped ball, circulating the ball up the completion string to surface and unsetting the packer element; 
         FIG. 7A  illustrates initiating completion of the next successive uphole interval initiated by dropping a successive, next larger size ball, for shifting the sleeve in the successive uphole fluid-jetting sub; 
         FIG. 7B  illustrates the optional step of reverse circulating down the annulus to recover the successive next larger size ball up the completion string to surface before repeating for each successive uphole zone and unsetting the packer; 
         FIG. 7C  illustrates the case where only some or no balls had been previously recovered, illustrating the step of reverse circulating down the annulus to recover all remaining balls in the completion string to surface; 
         FIG. 8  illustrates a final the step of having pulled the completion string out of hole for production from the formation through the jet perforated, second casing; 
         FIGS. 9 to 15  are schematic illustrations of an embodiment having a plurality of fluid-jetting subs incorporated in a completion string and spaced apart therealong, each sub incorporating one or more jet ports, a compressible packer element therebelow and an axially moveable sleeve for opening the jet ports and compressing the packer element in an open position, the completion string being jointed tubing, more particularly, 
         FIG. 9  illustrates the initial steps according to  FIG. 3 ; 
         FIG. 10  illustrates a next step of running in the completion string, for locating and spacing a plurality of the fluid-jetting subs having the compressible packer elements along the second casing string and forming a circulation annulus therebetween; 
         FIG. 11  illustrates commencement of jet perforation and treatment at a first interval initiated by a ball drop for the downhole zone for shifting the sleeve of the first, downhole-most fluid-jetting sub to the open position for enabling abrasive jetting and setting of the compressible packer 
         FIG. 12A  illustrates the next step of providing a fluid flow through the tubing string for maintaining a pressure on the sleeve for compressing the packer element and for applying abrasive fluid to the open jet ports for jet perforating the second casing string at the downhole zone of interest, enabling fracturing of the zone through the jet ports as desired; 
         FIG. 12B  illustrates an optional intermediate step of reverse circulating down the circulation annulus to recover the previous dropped ball, circulating the ball up the completion string to surface and unsetting the packer element; 
         FIG. 13A  illustrates initiating completion of the next successive uphole interval initiated by dropping a successive, next larger size ball, for shifting the sleeve in the successive uphole fluid-jetting sub; 
         FIG. 13B  illustrates the optional step of reverse circulating down the annulus to recover the successive next larger size ball up the completion string to surface before repeating for each successive uphole zone and unsetting the packer; 
         FIG. 14  illustrates the case where only some or no balls had been previously recovered, illustrating the step of reverse circulating down the annulus to recover all remaining balls in the completion string to surface and unsetting all of the remaining packer elements; 
         FIG. 15  illustrates having pulled the completion string from the wellbore according to  FIG. 8 ; 
         FIGS. 16 to 21  are schematic illustrations of an embodiment having a single fluid-jetting sub having one or more open jet ports, an inflatable packer element therebelow and one or more open packer ports fluidly connected to the packer element, the jet packer sub being run-in to the wellbore using coiled tubing having a blocked distal end; more particularly, 
         FIG. 16  illustrates the initial steps of completion of the wellbore according to  FIGS. 3 and 9 ; 
         FIG. 17  illustrates running in the coiled tubing having the single fluid-jetting sub positioned adjacent the blocked distal end and positioning the fluid-jetting sub adjacent a downhole-most zone of interest; 
         FIG. 18  illustrates flowing fluid through the coiled tubing for enabling fluid jetting from the open jet ports and inflation of the inflatable packer element through the open packer ports; 
         FIG. 19  illustrates stopping the flow of fluid through the coiled tubing for deflating the packer element and enabling re-positioning of the fluid-jetting sub at an uphole zone of interest; 
         FIG. 20  illustrates flowing fluid through the coiled tubing for enabling fluid jetting from the open jet ports and inflation of the inflatable packer element through the open packer ports at the uphole zone of interest; 
         FIG. 21  illustrates pulling the coiled tubing and fluid-jetting sub from the wellbore 
         FIGS. 22 to 27  are schematic illustrations of an embodiment having a single fluid-jetting sub having one or more open jet ports, a compressible packer element therebelow and a sleeve positioned below the jet ports and being axially moveable within the sub, the sleeve being operatively connected to the compressible packer element for compressing the packer element when actuated to move axially therein, the jet packer sub being run-in to the wellbore using coiled tubing having a flow port at a distal end; more particularly 
         FIG. 22  illustrates the initial steps of completion of the wellbore according to  FIGS. 3 ,  9  and  16 ; 
         FIG. 23  illustrates running in the coiled tubing having the single fluid-jetting sub positioned adjacent the distal end and positioning the fluid-jetting sub adjacent a downhole-most zone of interest; 
         FIG. 24  illustrates a ball drop engaging a ball seat on the sleeve, fluid pressure in the coiled tubing acting to axially compress the packer element and set the packer, fluid flowing through the coiled tubing enabling fluid jetting from the open jet ports; 
         FIG. 25  illustrates stopping the flow of fluid through the coiled tubing for unsetting the packer element and enabling re-positioning of the fluid-jetting sub at a next successive uphole zone of interest; 
         FIG. 26  illustrates initiating completion of the next successive uphole interval by seating a ball on the ball seat for axially compressing the packer element and setting the packer, fluid flowing through the coiled tubing enabling fluid jetting from the open jet ports; 
         FIG. 27  illustrates pulling the coiled tubing and fluid-jetting sub from the wellbore; 
     
    
    
     DESCRIPTION 
     Prior Art 
     Having reference to  FIG. 1 , a prior art jet sub  10 , of a plurality of such subs, is spaced along a wellbore. A jet sub housing  12  has a tool bore  14  fit with a sliding sleeve  16 . A plurality of jets  18  are fit to a wall  20  of the housing  12  and have jet ports  22  communicating between the tool bore  14  and an exterior of the housing  12 . The jet ports  22  are releaseably blocked by the sliding sleeve  16  when the sliding sleeve  16  is in a closed position. The sleeve  16  is temporarily secured axially within the housing  12  by shear pins  24  for blocking the jet ports  22 . The sleeve  16  has a ball seat  26  at an uphole end  28  for stopping a dropped ball  30  and sealing the tool bore  14 . Sufficient fluid pressure uphole of the ball  30  creates a shifting force to shear the shear pins  24  and shift the sleeve  16  downhole to an open position for opening the jet ports  22 . 
     Fluid-jetting Sub 
     Having reference to  FIGS. 3-27 , embodiments, disclosed herein, are fluid-jetting subs  40  which further incorporate a packer element  42  formed about the housing  12 , downhole of one or more jet ports  18  in the housing wall  20 . One or more of the fluid jetting subs  40  is incorporated into a completion string  44 , either at or near a distal end  46  thereof when a single sub  40  is used or spaced therealong when two or more of the subs  40  are used. The tool bore  14  is contiguous with a bore  45  of the completion string  44 . The packer element  42  is actuated to a set position to seal an annulus  48  between the sub  40  and a wellbore  50  by pressure which results from a flow of a fluid through the bore  45  of the completion string  44  and the tool bore  14 . Maintaining sufficient pressure in the completion string  44 , such as about 1000 psi greater than that in the annulus  48 , maintains the packer element  42  in the set position. Release of pressure within the completion string  44  releases the packer element  42  and permits movement of the completion string  44  within the wellbore  50  or removal of the completion string  44  therefrom. Further, the flow of fluid, such as an abrasive fluid, in the completion string  44  is directed through the jet ports  22  when the jet ports  22  are open. 
     Embodiments, disclosed herein are shown in the context of a horizontal wellbore which has been cased and cemented vertically using a primary casing and cased along the horizontal portion of the wellbore using a secondary uncemented casing. As one of skill in the art will appreciate however, embodiments can be used for completions wherein at least the horizontal portion of the wellbore is cased and uncemented, cased and cemented or is an uncased openhole. 
     Inflatable Packer Element 
     In one embodiment, as shown in  FIG. 2A , a fluid-jetting sub  40  having an inflatable packer element  42  is shown, prior to actuation. As stated above, one or more of such inflatable fluid-jetting subs  40  can be used. Where a plurality of packer jet subs  40  are used, the subs  40  are spaced and located along the completion string  44 , such as a  5 % inch jointed tubular completion string  44 . For example,  12  or more fluid-jetting subs  40  can be spaced along a portion of the completion string  44  extending  600  meters or more into a formation  56 . 
     As in the prior art sub  10 , each fluid-jetting sub  40  has the housing  12  and the tool bore  14  formed therethrough. The tool bore  14  is fit with the sliding sleeve  16 . One or more jets  18  are fit to the housing wall  20  and have the jet ports  22  communicating between the tool bore  14  and outside of the housing  2 . The jet ports  22  are releaseably blocked by the sliding sleeve  16 . The sleeve  16  is temporarily secured axially within the housing  12  by the shear pins  24  for blocking the jet ports  22 , when the sleeve  16  is in the closed position. A packer element  42 , which is inflatable and suitable for sealing to the wellbore  48  or to a casing  52  which is cemented or uncemented in the wellbore  50 , is formed about the housing  12  downhole of the jet ports  22 . One or more packer ports  54  are formed in the housing  12  between the tool bore  14  and the packer element  42  for providing fluid communication therebetween when the packer ports  54  are open. The sliding sleeve  16 , in a closed position, further releaseably blocks the packer ports  54 , such as to prevent premature actuation of the packer element  42 . 
     The sleeve  16  has the ball seat  26  at the uphole end  28  for stopping the dropped ball  30  and sealing the tool bore  14 . Fluid flowing through the completion string  44  causes sufficient fluid pressure uphole of the ball  30  to create the shifting force to shear the shear pins  24  and shift the sleeve  16  downhole to the open position for opening both the jet ports  22  and the packer ports  54 . 
     Each sleeve  16  of each of the plurality of fluid-jetting subs  40  has a ball seat  26  sized for a different diameter drop ball  30 , the downhole-most fluid-jetting sub  40  having the smallest ball seat  26 . Each successive uphole fluid-jetting sub&#39;s sleeve  16  has an incrementally larger ball seat  26  and corresponding ball  30 . Optionally, the downhole-most fluid-jetting sub  40  is absent a sleeve  16 , the jet ports  22  and packer ports  54  always being open. 
     As shown in greater detail in  FIG. 2B , the inflatable fluid-jetting sub  40 , when deployed, is located within the wellbore  50  or casing string  52 , forming the annulus  48  therebetween. When the ball  30  is dropped, the ball  30  seats at the uphole end  28  of the sleeve  16 . As fluid flows in the completion string  44  and the tool bore  14 , pressure increases causing the shear pin or pins  24  to be sheared and the sleeve  16  is shifted axially downhole to the open position to open the jet ports  24  and the packer ports  54 . Fluid flows from the tool bore  14  through the packer ports  54  into the packer element  42  to inflate and set the packer element  42 , sealing the annulus  48  about the fluid-jetting sub  40 . As the annulus  48  is sealed below the jet ports  22 , fluids F, such as abrasive fluids for jet perforating, flow from the jet ports  22  toward the casing  52  and cannot escape downhole past the set packer element  42 . Perforations are formed through the surrounding wellbore  50  or casing  52  and into the formation beyond. 
     Inflatable Fluid Jetting Sub—In use with a Jointed Tubular Completion String 
     In operation, and having reference to  FIG. 3 , a subterranean formation  56  is accessed, commencing with running in a first casing string  52   p  along a vertical portion  58  and heel  60  portion of the wellbore  50 . The first casing  52   p  is typically cemented therealong. An openhole, substantially horizontal portion  62  extends along zones of interest in the formation  56 . A second casing string  52   s  is run downhole into the openhole portion  62  for accessing the formation  56  therefrom in a cased operation or is left uncased in an openhole operation. 
     As shown in  FIG. 4 , the completion string  44 , typically a jointed tubular string, is run into the second casing  52   s,  the completion string  44  having a plurality of the fluid-jetting subs  40  adapted for incorporation therein, such as by threading, spaced apart and located therealong. Two fluid-jetting subs  40  are shown for illustrative purposes. 
     As shown in  FIG. 5 , jet perforation and treatment is commenced at a first dowhole-most interval by dropping the ball  30  which corresponds in size to the ball seat  26  of the sleeve  16  in the fluid-jetting sub  40  at the zone of interest. As shown, pressure increases within the completion tubing  44  and tool bore  14  and the sleeve  16  is caused to shift to the open position, opening fluid communication of the tool bore  14  with the jet ports  22  and the packer ports  54  for inflating the packer element  42 . 
     As shown in  FIG. 6A , the fluid F inflates the packer element  42 . Fluid, typically an abrasive fluid, is directed through the jet ports  22  for jet perforating the second casing string  52   s  at the downhole zone of interest. Treatment fluid, such as a fracturing fluid can be directed through the perforations in the secondary casing  52   s  through either the completion string  44  or the annulus  48 . If treatment fluid is provided through the annulus  48 , sufficient fluid must also be provided through the completion string  44  to maintain the pressure within the completion string above the annulus pressure, such as by about 1000 psi, so as to maintain the packer element  42  in the set position. After perforating and treating, delivery of a treatment fluid through the completion string  44  can be stopped or reduced and a clean-up fluid can be circulated either down the annulus  48  or through the completion string  44  for cleaning debris. A higher pressure in the annulus  48  than in the completion string  44  causes the inflatable packer element  42  to deflate, permitting fluid flow downhole past the fluid-jetting sub  40 . 
     One can then proceed to jet perforate at the next zone of interest, leaving the ball  30  within the tool bore  14  or completion string  44 . 
     Optionally, as shown in  FIG. 6B  one can perform an intermediate step of reverse circulating a fluid down the annulus  48  which enters the open jet ports  22  for circulating the ball  30  up the bore  45  of the completion string  44  to surface for recovery of the previously dropped ball  30 . 
       FIG. 7A  illustrates initiating completion of a next, successive, uphole interval. Jet perforation is initiated by dropping a successive, next larger size ball  30 , corresponding to the size of the ball seat  26  in the successive fluid-jetting sub  40  at the interval of interest. The ball drop shifts the sleeve  16  of the successive uphole sub  40 , enabling the jet ports  22  and inflatable packer element  42  as previously described. The packer element  42  inflates and abrasive fluid is applied to the jet ports  22  for jet perforating the second casing string  52   s  at the next uphole successive zone of interest. 
     Optionally once again, as shown in  FIG. 7B  the successive ball  30  can be reverse circulated to surface as described for  FIG. 6B  before repeating the process as described for each successive uphole zone. 
     Once all of the zones have been completed, if not already recovered individually, all of the balls  30  used in the completion can be recovered by reverse circulating down the annulus  48  to convey the balls  30  up the completion string  44  to surface.  FIG. 7C , illustrates the case where only some or no balls  30  had been previously recovered, illustrating the step of reverse circulating down the annulus  48  to recover all remaining balls  30  up the completion string  44  to surface. 
       FIG. 8  illustrates a final step of having pulled the completion string  44  out of hole (POOH) for production of hydrocarbons from the formation  56  through the perforations in the second casing  52   s.    
     Compressible Packer Element 
     Having reference to  FIGS. 9 to 15 , in an embodiment, a fluid-jetting sub  40  comprises a compressible packer element  70  instead of an inflatable packer element  42  having packer ports  54  as discussed above. A distal end  72  of the sleeve  16  is operatively connected to the compressible packer element  70 , such as at a collar, such that when the ball  30  seats in the ball seat  26  at the uphole end  28  of the sleeve  16 , pressure applied to the ball  30  causes the sleeve  16  to shift to the open position for opening the jet ports  22 , the distal end  72  applying sufficient force at the compressible packer element  70  for compressing or squeezing the packer element  70  into engagement with the casing  52   s  or wellbore  50 . Thus, the compressible packer element  70  is set for sealing the annulus  48  therebelow. 
     Compressible Fluid Jetting Sub—In use with a Jointed Tubular Completion String 
     In operation, and having reference to  FIG. 9 , a subterranean formation  56  is accessed, commencing with running in a first casing string  52   p  along a vertical portion  58  and heel  60  portion of the wellbore  50 . The first casing  52   p  is typically cemented therealong. An openhole, substantially horizontal portion  62  extends along zones of interest in the formation  56 . A second casing string  52   s  is run downhole into the openhole portion  62  for accessing the formation  56  therefrom in a cased operation or is left uncased in an openhole operation. 
     As shown in  FIG. 10 , the completion string  44 , typically a jointed tubular string, is run into the second casing  52   s,  the completion string  44  having a plurality of the compressible packer fluid-jetting subs  40  adapted for incorporation therein, such as by threading, spaced apart and located therealong. Two fluid-jetting subs  40  are shown for illustrative purposes. 
     As shown in  FIG. 11 , jet perforation and treatment is commenced at a first dowhole-most interval by dropping the ball  30  which corresponds in size to the ball seat  26  of the sleeve  16  in the fluid-jetting sub  40  at the zone of interest. As shown, pressure increases within the completion tubing  44  and tool bore  14  and the sleeve  16  is caused to shift to the open position, opening fluid communication of the tool bore  14  with the jet ports  22 , the distal end  72  of the sleeve  16  acting at the compressible packer element  70  for setting the packer element  70  as described above. 
     As shown in  FIG. 12A , the fluid pressure acting at the ball  30  acts to compress the packer element  70  for extruding the packer element  70  outwardly into contact with the casing  52   s.  Fluid F, typically an abrasive fluid, is directed through the jet ports  22  for jet perforating the second casing string  52   s  at the downhole zone of interest. Treatment fluid, such as a fracturing fluid can be directed through the perforations in the secondary casing  52   s  through either the completion string  44  or the annulus  48 . If treatment fluid is provided through the annulus  48 , sufficient fluid must also be provided through the completion string  44  to maintain the pressure within the completion string  44  above the annulus pressure, such as by about 1000 psi, so as to maintain the packer element  70  in the set position. After perforating and treating, delivery of a treatment fluid through the completion string  44  can be stopped or reduced and a clean-up fluid can be circulated either down the annulus  48  or through the completion string  44  for cleaning debris. A higher pressure in the annulus  48  than in the bore  45  of the completion string  44  causes the compressible packer element  70  to relax, permitting fluid flow downhole past the fluid-jetting sub  40 . 
     One can then proceed to jet perforate at the next zone of interest, leaving the ball  30  within the tool bore  14  or completion string  44 . 
     Optionally, as shown in  FIG. 12B  one can perform an intermediate step of reverse circulating a fluid down the annulus  48  to circulate the ball  30  up the bore  45  of the completion string  44  to surface for recovery of the previously dropped ball  30 . 
       FIG. 13A  illustrates initiating completion of a next, successive, uphole interval. Jet perforation is initiated by dropping a successive, next larger size ball  30 , corresponding to the size of the ball seat  26  in the successive fluid-jetting sub  40  at the interval of interest. The ball drop shifts the sleeve  16  of the successive uphole sub  40 , enabling the jet ports  22  and the compressible packer element  70  as previously described. The packer element  70  extrudes outwardly to seal against the casing  52   s  and abrasive fluid is applied to the jet ports  22  for jet perforating the second casing string  52   s  at the next uphole successive zone of interest. 
     Optionally once again, as shown in  FIG. 13B  the successive ball  30  can be reverse circulated to surface as described for  FIG. 12B  before repeating the process as described for each successive uphole zone. 
     Once all of the zones have been completed, if not already recovered individually, all of the balls  30  used in the completion can be recovered by reverse circulating down the annulus  48  to convey the balls  30  up the bore  45  of the completion string  44  to surface.  FIG. 14 , illustrates the case where only some or no balls  30  had been previously recovered, illustrating the step of reverse circulating down the annulus  48  to recover all remaining balls  30  up the bore  45  of the completion string  44  to surface. 
       FIG. 15  illustrates a final step of having pulled the completion string  44  out of hole (POOH) for production of hydrocarbons from the formation  56  through the perforations in the second casing  52   s.    
     Applicant believes that it is also possible to incorporate a plurality of spaced apart inflatable or compressible packer fluid-jetting subs  40  into a casing string  52  which is uncemented in the openhole portion  62  of the wellbore. A completion string  44  is not required. The casing string  52  is used as the completion string  44 , fluid being pumped through the casing string  52  to actuate the inflatable or compressible packer elements  42 ,  70  as described above and to deliver jets of fluid from the jet ports  22  for perforating the formation  56  thereabout. 
     Inflatable Fluid Jetting Sub—In use with a Coiled Tubing Completion String 
     In another embodiment, as illustrated in  FIGS. 16 through 21 , a completion string  44 , such as coiled tubing  80 , is fit with a single fluid-jetting sub  40  having an inflatable packer element  42 . The coiled tubing  80  is run in to the wellbore  50  for perforation and fracturing operations and is moved zone-by-zone therein. No sliding sleeve  16  or ball seat  26  is required to inflate the packer element  42 . Jet ports  22  and packer ports  54  remain open at all times. A distal end  82  of the coiled tubing  80  is blocked downhole from the single fluid-jetting sub  40 . Fluid pumped through the coiled tubing  80  actuates the inflatable packer element  42  through the open packer ports  54  and exits the open jet ports  22  for perforating the casing  52  or the wellbore  50  in an openhole operation. Fluid pressure is maintained in the coiled tubing  80  at a pressure greater than in the annulus  48  so as to maintain the packer element  42  in the inflated or set position during operation. 
     In operation, and having reference to  FIG. 16 , the subterranean formation  56  is accessed, commencing with running in a first casing string  52   p  along a vertical portion  58  and heel  60  portion of the wellbore  50 . The first casing  52   p  is typically cemented therealong. The openhole, substantially horizontal portion  62  extends along zones of interest in the formation  56 . The second casing string  52   s  is run downhole into the openhole portion  62  for accessing the formation  56  therefrom in a cased operation or is left uncased for an openhole operation. 
     As shown in  FIG. 17 , the coiled tubing deployed fluid-jetting sub  40  is run in the wellbore  50 , the fluid-jetting sub  40  being positioned at a first downhole-most zone of interest. 
     Having reference to  FIG. 18  fluid is pumped through the coiled tubing  80  to the tool bore  14 . Fluid is blocked at the distal end  82  of the coiled tubing  80  and is caused to enter the jet ports  22  and the packer ports  54  for inflating the inflatable packer element  42  and perforating and treating as previously described. 
     As shown in  FIG. 19 , once a zone is perforated and treated, such as by a fracturing operation, the inflatable packer element  42  is deflated, such as by reducing or stopping the flow of fluid through the coiled tubing  80  or by pumping fluid through the annulus  48  at a pressure greater than in the coiled tubing  80 . Once the packer element  42  is deflated, the coiled tubing string can be lifted for positioning the fluid-jetting sub adjacent a next, successive uphole zone of interest. 
     Once repositioned, as shown in  FIG. 20 , the process of setting the inflatable packer element  42  is repeated for sealing the annulus  48  therebelow and for jet perforation and treatment is repeated at the successive uphole zone. 
     As shown in  FIG. 21 , upon completion of the perforation and treatment processes in the wellbore the CT-conveyed fluid-jetting sub  40  is pulled out of the wellbore  50 . 
     Compressible Fluid Jetting Sub—In use with a Coiled Tubing Completion String 
     In yet another embodiment, as illustrated in  FIGS. 22 through 27 , a completion string  44 , such as coiled tubing  80 , is fit with a single fluid-jetting sub  40  having the compressible packer element  70 . The coiled tubing  80  is run in to the wellbore  50  for perforation and fracturing operations and is moved zone-by-zone therein. The sliding sleeve  16  and ball seat  26  are operatively connected to the compressible packer element  42  for compression of the packer element  70  to the set position. Jet ports  22  remain open at all times. A distal end  82  of the coiled tubing  80  is open downhole from the single fluid-jetting sub  40 . Fluid pumped through the coiled tubing  80  acts on a ball  30  dropped therein to engage the ball seat  26  for temporarily blocking the tool bore  14  and compressing the sleeve  16 , such as against a collar, for compressing the packer element  70  as described above. Fluid exits the open jet ports  22  for perforating the casing  52  or the wellbore  50  in an openhole operation. Fluid pressure is maintained in the coiled tubing  80  at a pressure greater than in the annulus  48  so as to maintain the packer element  70  in the compressed or set position during operation. 
     In operation, and having reference to  FIG. 22 , the subterranean formation  56  is accessed, commencing with running in a first casing string  52   p  along a vertical portion  58  and heel  60  portion of the wellbore  50 . The first casing  52   p  is typically cemented therealong. The openhole, substantially horizontal portion  62  extends along zones of interest in the formation  56 . The second casing string  52   s  is run downhole into the openhole portion  62  for accessing the formation  56  therefrom in a cased operation or is left uncased for an openhole operation. 
     As shown in  FIG. 23 , the coiled tubing deployed fluid-jetting sub  40  is run in the wellbore  50 , the fluid-jetting sub  40  being positioned at a first downhole-most zone of interest. 
     Having reference to  FIG. 24  fluid is pumped through the coiled tubing  80  to the tool bore  14 . Fluid is blocked at the ball  30  engaging the ball seat  26  and is caused to shift the sleeve  16  for compressing the compressible packer element  70  and to enter the jet ports  22  for perforating and treating as previously described and. 
     As shown in  FIG. 25 , once a zone is perforated and treated, such as by a fracturing operation, the compressible packer element  70  is relaxed, such as by reducing or stopping the flow of fluid through the coiled tubing  80  or by pumping fluid through the annulus  48  at a pressure greater than in the coiled tubing  80 . Once the packer element  42  is relaxed, the coiled tubing  80  can be lifted for positioning the fluid-jetting sub adjacent a next, successive uphole zone of interest. 
     Once repositioned, as shown in  FIG. 26 , the process of setting the inflatable packer element  42  is repeated for sealing the annulus  48  therebelow and for jet perforation and treatment is repeated at the successive uphole zone. 
     As shown in  FIG. 27 , upon completion of the perforation and treatment processes in the wellbore the CT-conveyed fluid-jetting sub  40  is pulled out of the wellbore  50 .