CA2810139A1

CA2810139A1 - Multizone and zone-by-zone abrasive jetting tools and methods for fracturing subterranean formations

Info

Publication number: CA2810139A1
Application number: CA2810139A
Authority: CA
Inventors: David Cook
Original assignee: CANADIAN FRACTURING Ltd
Current assignee: CANADIAN FRACTURING Ltd
Priority date: 2012-03-22
Filing date: 2013-03-21
Publication date: 2013-09-22
Also published as: US20130248192A1

Abstract

One or more fluid-jetting subs having jet ports and a packer element are incorporated into a completion string for deployment into a wellbore for perforation and treatment operations. The packer element, being either an inflatable packer element or a compressible packer element, is downhole of the jet ports and is fluid pressure actuated. Pressure in the completion string is maintained at a pressure higher than in the annulus thereabout to keep the packer set for sealing the annulus therebelow while fluid is delivered through the jet ports for perforating or treatment such as fracturing.

Description

1 "MULTIZONE AND ZONE-BY-ZONE ABRASIVE JETTING TOOLS AND

2 METHODS FOR FRACTURING SUBTERRANEAN FORMATIONS"

3

4 FIELD
6 Embodiments disclosed herein relate to systems, tools and methods 7 for jet perforating a tubular extending into a subterranean formation, the tool 8 releasably sealing an annulus about the tubular for controllably directing fluid for 9 forming the perforations and for fracturing the formation therethrough.

12 Horizontal wellbores in a formation are often lined with a primary 13 casing along the vertical portion and heel, the primary casing being cemented 14 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 16 the openhole portion of the wellbore for fracturing the wellbore to enhance 17 production therefrom.
18 It is also known to run in a production liner or secondary casing 19 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 21 liner is thereafter perforated at a plurality of locations spaced therealong and 22 corresponding to the zones of interest to create flowpaths therethrough to permit 23 fluids, such as fracturing fluids, to reach the formation therebeyond.

1 One method is to fit a completion string with a plurality of conventional 2 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 4 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 6 string.
The jet housing is fit with a plurality of jet ports oriented towards the wall of 7 the liner. The jet ports are alternately blocked or opened to the bore by a sliding 8 sleeve fit to the housing bore. The uphole end of the sleeve of each tool is sized to 9 receive a corresponding drop ball, each successive uphole tool in the completion string having a ball seat with a successively larger diameter.
11 In operation, the completion string with jet tools is run into the liner. A
12 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 14 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 17 through the jet ports and into the formation, fracturing the formation and directing 18 sand or other proppent into the formation. Some circulation of clean fluid continues 19 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.
21 The process is repeated with a next larger ball corresponding with the 22 diameter of the ball seat on the next uphole tool.

1 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 4 which enable more efficient and effective fracturing.

Embodiments disclosed herein enable setting and maintaining a 8 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 11 the sub for maintaining the packer element in the set position. In embodiments the 12 packer element is an inflatable element and in other embodiments the packer 13 element is a compressible packer element.
14 In one broad aspect, a fluid-jetting sub isdeployable 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 17 for connection to the completion string and having a tool bore formed therethrough 18 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 21 adapted to seal the annulus when actuated to a set position. A fluid block is formed 22 in the bore of the housing downhole of at least the plurality of jet ports for at least 1 temporarily blocking a flow of fluid through the tool bore therebelow.
When the fluid 2 is at least temporarily blocked, the fluid in the tool bore is caused to exit the plurality 3 of jet ports for delivering fluid therethrough for perforating and fracturing the 4 formation; and operatively engages the packer element for actuating the packer element to the set position.
6 In another broad aspect, a completion tool is deployable into a 7 wellbore on a completion string and forms an annulus therebetween for use in 8 perforating and fracturing a subterranean formation. The tool comprises:
one or 9 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 11 having a tool bore formed therethrough being contiguous with a bore of the 12 completion string. A plurality of jet ports extend substantially radially through the 13 tubular housing. A packer element is formed circumferentially about the housing 14 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 16 plurality of jet ports for at least temporarily blocking a flow of fluid through the tool 17 bore therebelow. When the fluid is at least temporarily blocked, the fluid flowing 18 through the bores of the tubing string and the fluid-jet sub is caused to exit the 19 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 21 element to the set position.

1 In an embodiment, the completion string is a jointed tubular string and 2 the one or more fluid-jetting subs is two or more fluid-jet subs, the two or more fluid-3 jet subs being spaced along the jointed tubular string for positioning at zones of 4 interest in the formation.
In another embodiment, the completion string is coiled tubing and the 6 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 8 interest in the formation.
9 In yet another broad aspect, a method for completion of a wellbore comprises: incorporating one or more fluid jetting subs into a completion tubing 11 string deployed into a wellbore and forming an annulus therebetween. Each of the 12 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 16 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 19 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 21 the packer element in the set position while providing treatment fluid through the

5 completion string or through the annulus for treating the formation through the 2 perforations.

Figure 1 is a sectional side view of a prior art jet sub, a plurality of

6 which are spaced along the wellbore;

7 Figure 2A is a sectional side view of an embodiment of a fluid jetting

8 sub having an one or more jet ports, an inflatable packer element therebelow and

9 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 11 by a sleeve in a closed position;
12 Figure 26 is a sectional side view of the inflatable fluid jetting sub of 13 Fig. 2A
following shifting of the sleeve to open the one or more jet ports for 14 perforation and the one or more packer ports for actuation of the packer element;
Figures 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 17 along a completion string,3-1/2 inch tubing string the completion string being jointed 18 tubing such as a3-1/2 inch tubing string, more particularly, 19 Fig.3 illustrates initial steps in completing access to a subterranean formation, commencing with running in a first casing string 21 along the vertical and heel portion of the wellbore, typically cementing the 22 first casing therealong, with open hole along the zones of interest and 1 running in a secondary casing string, such as 5-1/2 inch casing, into the open 2 hole portion for accessing the formation;
3 Fig. 4 illustrates a next step of running in the completion string 4 for locating and spacing a plurality of the fluid-jetting subs having the inflatable packer elements along the second casing string and forming a 6 circulation annulus therebetween;
7 Fig. 5 illustrates commencement of jet perforation and 8 treatment at a first interval initiated by a ball drop for the downhole zone for 9 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;
11 Fig. 6A illustrates the next step of providing a fluid flow through 12 the tubing string to the open packer ports for inflating the packer and 13 applying abrasive fluid to the open jet ports for jet perforating the second 14 casing string at the downhole zone of interest, enabling fracturing of the zone through the jet ports as desired;
16 Fig. 6B illustrates an optional intermediate step of reverse 17 circulating down the circulation annulus to recover the previous dropped ball, 18 circulating the ball up the completion string to surface and unsetting the 19 packer element;
Fig. 7A illustrates initiating completion of the next successive 21 uphole interval initiated by dropping a successive, next larger size ball, for 22 shifting the sleeve in the successive uphole fluid-jetting sub;

1 Fig. 7B
illustrates the optional step of reverse circulating down 2 the annulus to recover the successive next larger size ball up the completion 3 string to surface before repeating for each successive uphole zone and 4 unsetting the packer;
Fig. 7C illustrates the case where only some or no balls had 6 been previously recovered, illustrating the step of reverse circulating down 7 the annulus to recover all remaining balls in the completion string to surface;
8 Fig. 8 illustrates a final the step of having pulled the completion 9 string out of hole for production from the formation through the jet perforated, second casing;
11 Figures 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 14 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 16 jointed tubing, more particularly, 17 Fig. 9 illustrates the initial steps according to Fig. 3;
18 Fig.10 illustrates a next step of running in the completion string, 19 for locating and spacing a plurality of the fluid-jetting subs having the compressible packer elements along the second casing string and forming a 21 circulation annulus therebetween;

1 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 4 position for enabling abrasive jetting and setting of the compressible packer Fig. 12A illustrates the next step of providing a fluid flow 6 through the tubing string for maintaining a pressure on the sleeve for compressing the packer element and for applying abrasive fluid to the open 8 jet ports for jet perforating the second casing string at the downhole zone of 9 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 13 packer element;
14 Fig.
13A illustrates initiating completion of the next successive uphole interval initiated by dropping a successive, next larger size ball, for 16 shifting the sleeve in the successive uphole fluid-jetting sub;
17 Fig.
13B illustrates the optional step of reverse circulating down 18 the annulus to recover the successive next larger size ball up the completion 19 string to surface before repeating for each successive uphole zone and unsetting the packer;
21 Fig. 14 illustrates the case where only some or no balls had 22 been previously recovered, illustrating the step of reverse circulating down 1 the annulus to recover all remaining balls in the completion string to surface 2 and unsetting all of the remaining packer elements;
3 Fig. 15 illustrates having pulled the completion string from the 4 wellbore according to Fig. 8;
Figures 16 to 21 are schematic illustrations of an embodiment having 6 a single fluid-jetting sub having one or more open jet ports, an inflatable packer 7 element therebelow and one or more open packer ports fluidly connected to the 8 packer element, the jet packer sub being run-in to the wellbore using coiled tubing 9 having a blocked distal end; more particularly, Fig.16 illustrates the initial steps of completion of the wellbore 11 according to Figs. 3 and 9;
12 Fig.17 illustrates running in the coiled tubing having the single fluid-jetting sub positioned adjacent the blocked distal end and positioning 14 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 17 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;

1 Fig. 20 illustrates flowing fluid through the coiled tubing for enabling fluid jetting from the open jet ports and inflation of the inflatable 3 packer element through the open packer ports at the uphole zone of interest;
4 Fig. 21 illustrates pulling the coiled tubing and fluid-jetting sub from the wellbore 6 Figures 22 to 27 are schematic illustrations of an embodiment having 7 a single fluid-jetting sub having one or more open jet ports, a compressible packer 8 element therebelow and a sleeve positioned below the jet ports and being axially 9 moveable within the sub, the sleeve being operatively connected to the compressible packer element for compressing the packer element when actuated to 11 move axially therein, the jet packer sub being run-in to the wellbore using coiled 12 tubing having a flow port at a distal end; more particularly 13 Fig.22 illustrates the initial steps of completion of the wellbore 14 according to Figs. 3, 9 and 16;
Fig.23 illustrates running in the coiled tubing having the single 16 fluid-jetting sub positioned adjacent the distal end and positioning the fluid-17 jetting sub adjacent a downhole-most zone of interest;
18 Fig. 24 illustrates a ball drop engaging a ball seat on the 19 sleeve, fluid pressure in the coiled tubing acting to axially compress the packer element and set the packer, fluid flowing through the coiled tubing 21 enabling fluid jetting from the open jet ports;

1 Fig. 25 illustrates stopping the flow of fluid through the coiled 2 tubing for unsetting the packer element and enabling re-positioning of the 3 fluid-jetting sub at a next successive uphole zone of interest;
4 Fig. 26 illustrates initiating completion of the next successive uphole interval by seating a ball on the ball seat for axially compressing the 6 packer element and setting the packer, fluid flowing through the coiled tubing 7 enabling fluid jetting from the open jet ports;
8 Fig. 27 illustrates pulling the coiled tubing and fluid-jetting sub 9 from the wellbore;

3 Having reference to Fig. 1, a prior art jet sub 10, of a plurality of such 4 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 6 have jet ports 22 communicating between the tool bore 14 and an exterior of the 7 housing 12. The jet ports 22 are releaseably blocked by the sliding sleeve 16 when 8 the sliding sleeve 16 is in a closed position. The sleeve 16 is temporarily secured 9 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 11 sealing the tool bore 14. Sufficient fluid pressure uphole of the ball 30 creates a 12 shifting force to shear the shear pins 24 and shift the sleeve 16 downhole to an 13 open position for opening the jet ports 22.

FLUID-JETTING SUB
16 Having reference to Figs. 3-27, embodiments, disclosed herein, are 17 fluid-jetting subs 40 which further incorporate a packer element 42 formed about the 18 housing 12, downhole of one or more jet ports 18 in the housing wall 20.
One or 19 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 21 when two or more of the subs 40 are used. The tool bore 14 is contiguous with a 22 bore 45 of the completion string 44. The packer element 42 is actuated to a set 1 position to seal an annulus 48 between the sub 40 and a wellbore 50 by pressure 2 which results from a flow of a fluid through the bore 45 of the completion string 44 3 and the tool bore 14. Maintaining sufficient pressure in the completion string 44, 4 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 6 releases the packer element 42 and permits movement of the completion string 44 7 within the wellbore 50 or removal of the completion string 44 therefrom.
Further, the 8 flow of fluid, such as an abrasive fluid, in the completion string 44 is directed 9 through the jet ports 22 when the jet ports 22 are open.
Embodiments, disclosed herein are shown in the context of a 11 horizontal wellbore which has been cased and cemented vertically using a primary 12 casing and cased along the horizontal portion of the wellbore using a secondary 13 uncemented casing. As one of skill in the art will appreciate however, embodiments 14 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.

18 In one embodiment, as shown in Fig. 2A, a fluid-jetting sub 40 having 19 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 21 packer jet subs 40 are used, the subs 40 are spaced and located along the 22 completion string 44, such as a 5% inch jointed tubular completion string 44. For 1 example, 12 or more fluid-jetting subs 40 can be spaced along a portion of the 2 completion string 44 extending 600 meters or more into a formation 56.
3 As in the prior art sub 10, each fluid-jetting sub 40 has the housing 12 4 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 6 22 communicating between the tool bore 14 and outside of the housing 2.
The jet 7 ports 22 are releaseably blocked by the sliding sleeve 16. The sleeve 16 is 8 temporarily secured axially within the housing 12 by the shear pins 24 for blocking 9 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 11 is cemented or uncemented in the wellbore 50, is formed about the housing 12 12 downhole of the jet ports 22. One or more packer ports 54 are formed in the 13 housing 12 between the tool bore 14 and the packer element 42 for providing fluid 14 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 16 as to prevent premature actuation of the packer element 42.
17 The sleeve 16 has the ball seat 26 at the uphole end 28 for stopping 18 the dropped ball 30 and sealing the tool bore 14. Fluid flowing through the 19 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 21 open position for opening both the jet ports 22 and the packer ports 54.

1 Each sleeve 16 of each of the plurality of fluid-jetting subs 40 has a 2 ball seat 26 sized for a different diameter drop ball 30, the downhole-most fluid-3 jetting sub 40 having the smallest ball seat 26. Each successive uphole fluid-jetting 4 sub'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 6 ports 22 and packer ports 54 always being open.
7 As shown in greater detail in Fig. 2B, the inflatable fluid-jetting sub 40, 8 when deployed, is located within the wellbore 50 or casing string 52, forming the 9 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 11 tool bore14, pressure increases causing the shear pin or pins 24 to be sheared and 12 the sleeve 16 is shifted axially downhole to the open position to open the jet ports 13 24 and the packer ports 54. Fluid flows from the tool bore 14 through the packer 14 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 16 jet ports 22, fluids F, such as abrasive fluids for jet perforating, flow from the jet 17 ports 22 toward the casing 52 and cannot escape downhole past the set packer 18 element 42. Perforations are formed through the surrounding wellbore 50 or casing 19 52 and into the formation beyond.

4 In operation, and having reference to Fig. 3, a subterranean formation 56 is accessed, commencing with running in a first casing string 52p along a vertical 6 portion 58 and heel 60 portion of the wellbore 50. The first casing 52p is typically 7 cemented therealong. An openhole, substantially horizontal portion 62 extends 8 along zones of interest in the formation 56. A second casing string 52s is run 9 downhole into the openhole portion 62 for accessing the formation 56 therefrom in a cased operation or is left uncased in an openhole operation.
11 As shown in Fig. 4, the completion string 44, typically a jointed tubular 12 string, is run into the second casing 52s, the completion string 44 having a plurality 13 of the fluid-jetting subs 40 adapted for incorporation therein, such as by threading, 14 spaced apart and located therealong. Two fluid-jetting subs 40 are shown for illustrative purposes.
16 As shown in Fig. 5, jet perforation and treatment is commenced at a 17 first dowhole-most interval by dropping the ball 30 which corresponds in size to the 18 ball seat 26 of the sleeve 16 in the fluid-jetting sub 40 at the zone of interest. As 19 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 21 tool bore 14 with the jet ports 22 and the packer ports 54 for inflating the packer 22 element 42.
23 As shown in Fig. 6A, the fluid F inflates the packer element 42.
Fluid, 24 typically an abrasive fluid, is directed through the jet ports 22 for jet perforating the 1 second casing string 52s at the downhole zone of interest. Treatment fluid, such as 2 a fracturing fluid can be directed through the perforations in the secondary casing 3 52s through either the completion string 44 or the annulus 48. If treatment fluid is 4 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 6 annulus pressure, such as by about 1000psi, so as to maintain the packer element 7 42 in the set position. After perforating and treating, delivery of a treatment fluid 8 through the completion string 44 can be stopped or reduced and a clean-up fluid 9 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 11 44 causes the inflatable packer element 42 to deflate, permitting fluid flow downhole 12 past the fluid-jetting sub 40.
13 One can then proceed to jet perforate at the next zone of interest, 14 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 16 of reverse circulating a fluid down the annulus 48 which enters the open jet ports 22 17 for circulating the ball 30 up the bore 45 of the completion string 44 to surface for 18 recovery of the previously dropped ball 30.
19 Fig. 7A illustrates initiating completion of a next, successive, uphole interval. Jet perforation is initiated by dropping a successive, next larger size ball 21 30, corresponding to the size of the ball seat 26 in the successive fluid-jetting sub 22 40 at the interval of interest. The ball drop shifts the sleeve 16 of the successive 1 uphole sub 40, enabling the jet ports 22 and inflatable packer element 42 as 2 previously described. The packer element 42 inflates and abrasive fluid is applied 3 to the jet ports 22 for jet perforating the second casing string 52s at the next uphole 4 successive zone of interest.
Optionally once again, as shown in Fig. 7B the successive ball 30 can 6 be reverse circulated to surface as described for Fig. 6B before repeating the 7 process as described for each successive uphole zone.
8 Once all of the zones have been completed, if not already recovered 9 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 11 to surface. Fig. 7C, illustrates the case where only some or no balls 30 had been 12 previously recovered, illustrating the step of reverse circulating down the annulus 48 13 to recover all remaining balls 30 up the completion string 44 to surface.
14 Figure 8 illustrates a final step of having pulled the completion string 44 out of hole (POOH) for production of hydrocarbons from the formation 56 16 through the perforations in the second casing 52s.

19 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 21 element 42 having packer ports 54 as discussed above. A distal end 72 of the 22 sleeve 16 is operatively connected to the compressible packer element 70, such as 1 at a collar, such that when the ball 30 seats in the ball seat 26 at the uphole end 28 2 of the sleeve 16, pressure applied to the ball 30 causes the sleeve 16 to shift to the 3 open position for opening the jet ports 22, the distal end 72 applying sufficient force 4 at the compressible packer element 70 for compressing or squeezing the packer element 70 into engagement with the casing 52s or wellbore 50. Thus, the 6 compressible packer element 70 is set for sealing the annulus 48 therebelow.

11 In operation, and having reference to Fig. 9, a subterranean formation 12 56 is accessed, commencing with running in a first casing string 52p along a vertical 13 portion 58 and heel 60 portion of the wellbore 50. The first casing 52p is typically 14 cemented therealong. An openhole, substantially horizontal portion 62 extends along zones of interest in the formation 56. A second casing string 52s is run 16 downhole into the openhole portion 62 for accessing the formation 56 therefrom in a 17 cased operation or is left uncased in an openhole operation.
18 As shown in Fig. 10, the completion string 44, typically a jointed 19 tubular string, is run into the second casing 52s, the completion string 44 having a plurality of the compressible packer fluid-jetting subs 40 adapted for incorporation 21 therein, such as by threading, spaced apart and located therealong. Two fluid-22 jetting subs 40 are shown for illustrative purposes.
23 As shown in Fig. 11, jet perforation and treatment is commenced at a 24 first dowhole-most interval by dropping the ball 30 which corresponds in size to the 1 ball seat 26 of the sleeve 16 in the fluid-jetting sub 40 at the zone of interest. As 2 shown, pressure increases within the completion tubing 44 and tool bore 14 and the 3 sleeve 16 is caused to shift to the open position, opening fluid communication of the 4 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 6 above.
7 As shown in Fig. 12A, the fluid pressure acting at the ball 30 acts to 8 compress the packer element 70 for extruding the packer element 70 outwardly into 9 contact with the casing 52s. Fluid F, typically an abrasive fluid, is directed through the jet ports 22 for jet perforating the second casing string 52s at the downhole zone 11 of interest. Treatment fluid, such as a fracturing fluid can be directed through the 12 perforations in the secondary casing 52s through either the completion string 44 or 13 the annulus 48. If treatment fluid is provided through the annulus 48, sufficient fluid 14 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 16 1000psi, so as to maintain the packer element 70 in the set position.
After 17 perforating and treating, delivery of a treatment fluid through the completion string 18 44 can be stopped or reduced and a clean-up fluid can be circulated either down 19 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 21 the compressible packer element 70 to relax, permitting fluid flow downhole past the 22 fluid-jetting sub 40.

1 One can then proceed to jet perforate at the next zone of interest, 2 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 4 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 6 30.
7 Fig.
13A illustrates initiating completion of a next, successive, uphole interval. Jet perforation is initiated by dropping a successive, next larger size ball 9 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 11 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 13 the casing 52s and abrasive fluid is applied to the jet ports 22 for jet perforating the 14 second casing string 52s at the next uphole successive zone of interest.
Optionally once again, as shown in Fig. 13B the successive ball 30 16 can be reverse circulated to surface as described for Fig. 12B before repeating the 17 process as described for each successive uphole zone.
18 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 22 balls 30 had been previously recovered, illustrating the step of reverse circulating 1 down the annulus 48 to recover all remaining balls 30 up the bore 45 of the 2 completion string 44 to surface.
3 Figure 15 illustrates a final step of having pulled the completion string 4 44 out of hole (POOH) for production of hydrocarbons from the formation through the perforations in the second casing 52s.
6 Applicant believes that it is also possible to incorporate a plurality of 7 spaced apart inflatable or compressible packer fluid-jetting subs 40 into a casing 8 string 52 which is uncemented in the openhole portion 62 of the wellbore.
A
9 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 11 or compressible packer elements 42, 70 as described above and to deliver jets of 12 fluid from the jet ports 22 for perforating the formation 56 thereabout.

COMPLETION STRING

17 In another embodiment, as illustrated in Figs. 16 through 21, a 18 completion string 44, such as coiled tubing 80, is fit with a single fluid-jetting sub 40 19 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 21 therein. No sliding sleeve 16 or ball seat 26 is required to inflate the packer element 22 42. Jet ports 22 and packer ports 54 remain open at all times. A distal end 82 of the 23 coiled tubing 80 is blocked downhole from the single fluid-jetting sub 40. Fluid 1 pumped through the coiled tubing 80 actuates the inflatable packer element 2 through the open packer ports 54 and exits the open jet ports 22 for perforating the 3 casing 52 or the wellbore 50 in an openhole operation. Fluid pressure is maintained 4 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.
6 In operation, and having reference to Fig. 16, the subterranean 7 formation 56 is accessed, commencing with running in a first casing string 52p 8 along a vertical portion 58 and heel 60 portion of the wellbore 50. The first casing 9 52p is typically cemented therealong. The openhole, substantially horizontal portion 62 extends along zones of interest in the formation 56. The second casing string 11 52s is run down hole into the openhole portion 62 for accessing the formation 56 12 therefrom in a cased operation or is left uncased for an openhole operation.
13 As shown in Fig. 17, the coiled tubing deployed fluid-jetting sub 40 is 14 run in the wellbore 50, the fluid-jetting sub 40 being positioned at a first downhole-most zone of interest.
16 Having reference to Fig. 18 fluid is pumped through the coiled tubing 17 80 to the tool bore 14. Fluid is blocked at the distal end 82 of the coiled tubing 80 18 and is caused to enter the jet ports 22 and the packer ports 54 for inflating the 19 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 21 by a fracturing operation, the inflatable packer element 42 is deflated, such as by 22 reducing or stopping the flow of fluid through the coiled tubing 80 or by pumping 1 fluid through the annulus 48 at a pressure greater than in the coiled tubing 80. Once 2 the packer element 42 is deflated, the coiled tubing string can be lifted for 3 positioning the fluid-jetting sub adjacent a next, successive uphole zone of interest.
4 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 6 for jet perforation and treatment is repeated at the successive uphole zone.
7 As shown in Fig. 21, upon completion of the perforation and treatment 8 processes in the wellbore the CT-conveyed fluid-jetting sub 40 is pulled out of the 9 wellbore 50.

14 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 16 having the compressible packer element 70. The coiled tubing 80 is run in to the 17 wellbore 50 for perforation and fracturing operations and is moved zone-by-zone 18 therein. The sliding sleeve 16 and ball seat 26 are operatively connected to the 19 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 21 tubing 80 is open downhole from the single fluid-jetting sub 40. Fluid pumped 22 through the coiled tubing 80 acts on a ball 30 dropped therein to engage the ball 23 seat 26 for temporarily blocking the tool bore 14 and compressing the sleeve 16, 1 such as against a collar, for compressing the packer element 70 as described 2 above.
Fluid exits the open jet ports 22 for perforating the casing 52 or the wellbore 3 50 in an openhole operation. Fluid pressure is maintained in the coiled tubing 80 at 4 a pressure greater than in the annulus 48 so as to maintain the packer element in the compressed or set position during operation.
6 In operation, and having reference to Fig. 22, the subterranean formation 56 is accessed, commencing with running in a first casing string 52p 8 along a vertical portion 58 and heel 60 portion of the wellbore 50. The first casing 9 52p is typically cemented therealong. The openhole, substantially horizontal portion 62 extends along zones of interest in the formation 56. The second casing string 11 52s is run downhole into the openhole portion 62 for accessing the formation 56 12 therefrom in a cased operation or is left uncased for an openhole operation.
13 As shown in Fig. 23, the coiled tubing deployed fluid-jetting sub 40 is 14 run in the wellbore 50, the fluid-jetting sub 40 being positioned at a first downhole-most zone of interest.
16 Having reference to Fig. 24 fluid is pumped through the coiled tubing 17 80 to the tool bore 14. Fluid is blocked at the ball 30 engaging the ball seat 26 and 18 is caused to shift the sleeve 16 for compressing the compressible packer element 19 70 and to enter the jet ports 22 for perforating and treating as previously described and.
21 As shown in Fig. 25, once a zone is perforated and treated, such as 22 by a fracturing operation, the compressible packer element 70 is relaxed, such as 1 by reducing or stopping the flow of fluid through the coiled tubing 80 or by pumping 2 fluid through the annulus 48 at a pressure greater than in the coiled tubing 80. Once 3 the packer element 42 is relaxed, the coiled tubing 80 can be lifted for positioning 4 the fluid-jetting sub adjacent a next, successive uphole zone of interest.
Once repositioned, as shown in Fig. 26, the process of setting the 6 inflatable packer element 42 is repeated for sealing the annulus 48 therebelow and 7 for jet perforation and treatment is repeated at the successive uphole zone.
8 As shown in Fig. 27, upon completion of the perforation and treatment 9 processes in the wellbore the CT-conveyed fluid-jetting sub 40 is pulled out of the wellbore 50.

Claims

EMBODIMENTS IN WHICH AN EXCLUSIVE PROPERTY OR
PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:

1. A fluid-jetting sub, deployable into a wellbore on a completion string and forming an annulus therebetween, for use in perforating and fracturing a subterranean formation comprising:
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 extending substantially radially through the tubular housing;
a packer element formed circumferentially about the housing downhole of the plurality of jet ports and adapted to seal the annulus when actuated to a set position; and a fluid block 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, wherein 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 to operatively engage the packer element for actuating the packer element to the set position.

2. The fluid-jetting sub of claim 1 wherein the packer element is an inflatable element, the sub further comprising:
one or more packer ports extending radially through the housing for fluidly connecting between the tool bore and the packer element uphole of the fluid block, the fluid entering the one or more packer ports for operatively engaging the packer element for inflating the packer element to the set position.

3. The fluid-jetting sub of claim 2 further comprising a sliding sleeve positioned within the tool bore and axially moveable therein to cover the plurality of jet ports and the one or more packer ports in a closed position and to open the plurality of jet ports and the one or more packer ports in an open position.

4. The fluid-jetting sub of claim 3 further comprising:
a ball seat operatively connected to the sleeve and adapted to receive a ball dropped into the bore of the housing for forming the fluid block, fluid pressure acting at the fluid block for axially moving the sleeve from the closed position to the open position for delivering fluid through the plurality of jet ports and through the one or more packer ports.

5. The fluid-jetting sub of claim 1 wherein the packer element is a compressible element, the sub further comprising:
a ball seat operatively engaging the packer element and adapted to receive a ball dropped into the bore of the housing for forming the fluid block, fluid pressure acting at the ball sealed in the ball seat for compressing the packer element to the set position.

6. The fluid-jetting sub of claim 5 further comprising:
a sliding sleeve positioned within the tool bore and axially moveable therein to cover the plurality of jet ports in a closed position, the sliding sleeve being operatively connected to the packer element, the ball seat being formed on the sliding sleeve, wherein fluid pressure acting at the ball sealed in the ball seat moves the sliding sleeve axially from the closed position to an open position for opening the plurality of jet ports and for acting to compress the packer element to the set position.

7. A completion tool deployable into a wellbore on a completion string and forming an annulus therebetween for use in perforating and fracturing a subterranean formation comprising:
one or more fluid-jet subs incorporated in the completion string, each of the one or more fluid-jet subs having 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 extending substantially radially through the tubular housing;
a packer element formed circumferentially about the housing downhole of the plurality of jet ports for sealing the annulus when actuated to a set position; and a fluid block 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, wherein 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.

8. The completion tool of claim 7 wherein 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 are spaced along the jointed tubular string for positioning at zones of interest in the formation.

9. The completion tool of claim 7 wherein the completion string as 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.

10. A method for completion of a wellbore comprising:
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 having 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 formed about the housing therebelow;
at least temporarily blocking the flow of fluid through the tool bore below at least the jet ports;

flowing fluid through the contiguous bore for increasing pressure within the tool bore to greater than outside the housing, the pressure acting 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; and maintaining the pressure 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.