CN103781989B - Multi-Zone Fracturing Completions - Google Patents

Abstract

A wellbore completion is disclosed. The wellbore completion includes a casing assembly comprising a plurality of casing segments (406). At least one collar (410) is positioned to connect the casing segments (406). The at least one collar (410) includes a tubular body having an internal flow path and at least one fracturing port (412) configured to provide fluid communication between an outer surface of the collar and the internal flow path. A coiled tubing section (442) may be positioned in the casing assembly. The coiled tubing includes an internal flow path, wherein an annulus (450) is formed between the coiled tubing and the casing assembly. The bottom hole assembly (302) is connected to coiled tubing (442). The bottom hole assembly includes a fracturing bore (444) configured to provide fluid communication between the interior flow path of the coiled tubing and the annulus. The packer (430) may be positioned to allow contact with the at least one collar when the packer is expanded. The packer (430) is capable of isolating the annulus above the packer from the annulus below the packer so that fluid flowing down the coiled tubing can create a pressure differential across the packer to open the fracture port.

Description

Multi-Zone Fracturing Completions

related application

This disclosure is a continuation-in-part of U.S. Patent Application No. 12/971,932, filed December 17, 2010, entitled "MULTI-ZONE FRACTURING COMPLETION," by John Edward Ravensbergen and Lyle A continuation-in-part of U.S. Patent Application No. 12/842,099, filed July 23, 2010, entitled "BOTTOM HOLE ASSEMBLY WITH PORTEDCOMLETION AND METHODS OF FRACTURING THEREWITH," U.S. Patent Application No. 12/842,099 claims John Edward Ravensbergen in 2009 Priority to U.S. Provisional Patent Application No. 61/228,793, filed July 27, 1999, entitled "BOTTOM HOLE ASSEMBLY WITH PORTED COMPLETION AND METHODS OF FRACTURING THEREWITH," each of which is hereby incorporated by reference in its entirety.

technical field

The present disclosure relates generally to downhole tools for use in oil and gas wells, and more particularly to a ported completion that may be used to fracture in multi-zone oil and gas wells.

Background technique

Oil and gas well completions are typically performed after the hydrocarbon production wellbore is drilled. Part of the well completion process includes running the well casing assembly into the well. The casing assembly may include a plurality of tubular casing sections connected together by collars. A standard coupling may, for example, be a relatively short tubular or annular structure with internal threads on one end for connection to the externally threaded ends of multiple casing sections. Oil and gas well casing assemblies can be placed in the wellbore by various techniques. One such technique involves filling the annular space between the wellbore and the outer diameter of the casing with cement.

After the casing is placed in the wellbore, perforating and fracturing operations may be performed. Generally, perforation entails creating an opening through the casing of the oil and gas well and into the formation by generally known devices such as perforating guns or hydraulic sandblasting perforators. Thereafter, the perforated zone may be hydraulically isolated and a fracturing operation performed to increase the size of the initially formed opening in the formation. Efforts are made to introduce frac sand material into the enlarged openings to prevent these openings from closing.

Currently, techniques have been developed to perform perforating and fracturing operations using coiled tubing strings. One such technique, known as the continuous annular tubular fracturing process or simply the ACT-Frac process, is disclosed in US Patent Nos. 6,474,419, 6,394,184, 6,957,701 and 6,520,255, which are hereby incorporated by reference in their entirety. In order to practice the techniques described in the aforementioned patents, a work string including a bottomhole assembly (BHA) is generally maintained in the wellbore during fracturing operations.

One method of perforating, known as the hydroblasting procedure, involves the use of mortar to punch holes through the casing, cement and into the formation of the oil and gas well. Fracturing can then be performed through these holes. One of the problems with hydroblasting perforating is that the sand particles from the perforating process can remain in the wellbore annulus and can interfere with the fracturing process. Consequently, cleaning sand out of the wellbore in some cases can be a lengthy process, taking one or more hours per production zone in a well. Another problem with hydroblast perforation is consuming too much fluid to cut the perforation and circulate excess solids from the oil and gas well before and during the frac treatment or pump the hydroblast perforating fluid and grit into the zone middle. What is needed in the industry is to go to more and more zones in multi-zone wells, some horizontal wells can have 40 zones or more. Removing grit from such a large area adds significant processing time, requires excessive use of fluids, and increases cost. Excessive use of fluids can also affect the environment. For example, the process requires more trucking, vat capacity and heating, and in addition these same requirements are necessary when recovering the fluids from oil and gas wells.

Well completion techniques that do not require perforation are known in the art. One such technique is called a packer-and-pattern completion. As an alternative to cemented completions, this technique requires running a perforated packer into the wellbore to set the casing assembly. The bushing assembly includes a ported collar having a bushing. These ports can be opened by operating the sliding bushing after the casing has been placed in the well. Fracturing can then be performed through these ports.

For multi-zone wells, multiple ported collars combined with sliding bushing assemblies have been used. The sliding bushing fits on the inner diameter of the sleeve and/or bushing and can be held in place by shear pins. In some designs, the bottommost bushing can be hydraulically opened by applying a pressure differential to the bushing assembly. After the casing with end collars has been installed, a fracturing process is performed on the bottommost region of the well. The process may include hydraulically sliding the liner in the first zone to open the port, and then pumping fracturing fluid into the formation through the opened port of the first zone. After fracturing the first zone, drop a ball down the well. The ball hits the next liner up from the first fracture zone in the middle, thereby opening the port for fracturing the second zone. After fracturing the second zone, a second ball, slightly larger than the first ball, is dropped to open ports for fracturing the third zone. The process is repeated using progressively larger balls to open each successively higher zone in the well until all zones are fractured. However, because the well diameter is limited in size and the ball size generally increases in quarter foot increments, the process is limited to only about 11 or 12 zones in the well before the ball size is exhausted. In addition, the cost of using sliding liner assemblies and packers for setting oil and gas well casings in this method is relatively high. Additionally, sliding bushing assemblies and balls can significantly reduce the inside diameter of the bushing, which is often not ideal. Grinding out the ball and ball bearing from the casing is often necessary after the frac stimulation treatment is complete.

Another method used in open hole wells (using a packer to secure the casing in the well) is similar to the packer-plus-style completion described above, except that the liner of the assembly is configured to open mechanically instead of opening the port by a drop ball outside. For example, a transition tool may be used to open and close the liner for fracturing and/or other desired purposes. As in the case of packer-and-pattern completions, the cost of using a sliding liner assembly and packers for setting the well casing in this method is high. Additionally, sliding bushing assemblies can undesirably reduce the inner diameter of the sleeve. Additionally, these bushings are prone to failure due to high velocity mortar erosion and/or sand particles interfering with the mechanism.

In co-pending U.S. Patent Application No. 12/826,372, filed June 29, 2010, by Lyle E. Laun, entitled "JOINT ORCOUPLING DEVICE INCORPORATING AMECHANICALLY-INDUCED WEAK POINT AND METHOD OFUSE," discloses an Another technique for splitting wells, which is hereby incorporated by reference in its entirety.

The present disclosure seeks to overcome, or at least reduce the effects of, one or more of the problems described above.

Contents of the invention

The following presents an overview of the disclosure in order to provide an understanding of some of the aspects disclosed herein. This summary is not an exhaustive overview and it does not intend to identify key or critical elements of the disclosure or to delineate the scope of the invention as recited in the appended claims.

One embodiment of the present disclosure is a wellbore completion system that includes a housing operably connected to a string of casing. The housing includes at least one port therethrough and a bushing connected to the housing, the bushing being movable between an open position and a closed position. In the closed position, the bushing prevents fluid communication through the housing port. The system includes a bottom hole assembly having a packing element and a fixture. The fixture is adapted to selectively connect the bottom hole assembly to the liner. The packing element is adapted to provide a seal between the bottom hole assembly and the liner.

The wellbore completion system may also include a shearable device adapted to selectively retain the liner in an initially closed position and release the liner upon application of a predetermined amount of force. The system may include an expandable device adapted to selectively maintain the liner in the open position after the liner has been released and moved from the closed position. The expandable device may be adapted to engage a recess in the housing. The bottom hole assembly is connected to coiled tubing that can be used to position the bottom hole assembly proximate to the ported casing. The bottom hole assembly may include a collar casing positioner. The bottom hole assembly's anchors and packing elements may be pressure actuated. The wellbore completion system may include a plurality of ported housings along the casing string, each housing including a bushing movable between a closed position and an open position.

One embodiment of the present disclosure is a method for treating or stimulating an oil and gas well formation. The method includes positioning a bottom hole assembly within a portion of a string of casing proximate a first liner operably connected to the string of casing. The bushing is movable between a first position preventing fluid communication through the first port in the casing string and a second position allowing fluid communication through the first port in the casing string. The method includes connecting a portion of the bottom hole assembly to the first bushing and moving the bottom hole assembly to move the first bushing from a first or closed position to a second or open position.

The method may include treating an oil and gas well formation proximate to a first port in the casing string. The method may also include disconnecting the bottom hole assembly from the first liner and positioning the bottom hole assembly proximate to a second liner operatively connected to the string of casing. The second bushing is movable between a first position preventing fluid communication through the second port in the casing string and a second position allowing fluid communication through the second port. The method may include connecting a portion of the bottom hole assembly to the second bushing and moving the bottom hole assembly to move the second bushing from a closed position to an open position. The method may include treating a well formation proximate to the second port.

Connecting a portion of the bottom hole assembly to the liner may include actuating a fixture to engage a portion of the liner. The method may include forming a seal between the bottom hole assembly and the liner. The method may include selectively releasing the liner from its first position prior to moving the bottom hole assembly to move the liner. The liner can optionally include a shearable device that can be adjusted by increasing the pressure in the casing string above the bottom hole assembly, moving the coiled tubing down the casing string, or increasing the pressure and moving the coiled tubing at the same time. Combine to cut shearable devices. The method may include selectively maintaining the bushing in an open position. Positioning the bottom hole assembly and connecting the bottom hole assembly to the liner may include moving the coiled tubing in an upward direction only. The method may include pumping fluid down the coiled tubing to actuate a fixture of the bottom hole assembly.

One embodiment of the invention relates to a wellbore completion. The wellbore completion includes a casing assembly including a plurality of casing sections. At least one collar is positioned to connect the casing sections. The at least one collar includes a tubular body having an inner flow path and at least one frac port configured to provide fluid communication between an outer surface of the collar and the inner flow path. The coiled tubing section may be located in a casing assembly. The coiled tubing includes an internal flow path wherein an annulus is formed between the coiled tubing and casing assembly. The bottom hole assembly is connected to coiled tubing. The bottom hole assembly includes a frac hole configured to provide fluid communication between an internal flow path of the coiled tubing and the annulus. The packer may be positioned such that it is capable of contacting the at least one collar when the packer is expanded. The packer can isolate the annulus above the packer from the annulus below the packer so that the fluid flowing down the coiled tubing can create a pressure difference on both sides of the packer, thereby sealing the fracture port Open.

Another embodiment of the present invention relates to a method for effecting hydrocarbon production wellbore completions. The method includes running coiled tubing into a casing assembly in a wellbore. The casing assembly includes a plurality of casing sections and one or more collars positioned to connect the casing sections together. A first collar of the one or more collars includes a first frac port. Fluid is pumped through the coiled tubing to apply a pressure differential to open the first frac port of a casing assembly. The well formation is fractured by flowing a fracturing fluid through the first fracturing port.

Description of drawings

Figure 1 shows a portion of a cemented wellbore completion according to one embodiment of the present disclosure.

FIG. 2 shows an enlarged view of a collar and bottom hole assembly used in the wellbore completion of FIG. 1 , according to one embodiment of the present disclosure.

Figure 3 illustrates an enlarged view of a locking pawl used in the wellbore completion of Figure 1, according to one embodiment of the present disclosure.

Figure 4 shows a perspective view of a collar according to one embodiment of the present disclosure.

Figure 5 illustrates a cross-sectional view of the collar of Figure 4, according to one embodiment of the present disclosure.

Figure 6 illustrates a valve for use in the collar of Figure 4, according to one embodiment of the present disclosure.

Figure 7 illustrates a coiled tubing string used with a coiled tubing string and a spanning cup tool with a packer for isolating a zone in the well to be fractured, according to one embodiment of the present disclosure.

Figure 8 illustrates a portion of an oil and gas well completion with an open hole packer according to one embodiment of the present disclosure.

Figure 9 shows an enlarged view of a collar and bottom hole assembly according to one embodiment of the present disclosure.

Figure 10 illustrates a bottomhole assembly used in a wellbore completion according to one embodiment of the present disclosure.

FIG. 11 shows an enlarged view of the upper portion of the bottom hole assembly and collar shown in FIG. 10 .

FIG. 12 shows an enlarged view of the lower portion of the bottom hole assembly and collar shown in FIG. 10 .

13 shows an enlarged view of a portion of a mandrel of a bottom hole assembly according to one embodiment of the present disclosure.

FIG. 14 shows a cross-sectional end view of the collar of FIG. 11 .

15 illustrates a cross-sectional view of a collar with a valve in a closed position, according to one embodiment of the present disclosure.

16 illustrates a coiled tubing string for use with a coiled tubing string and a spanning cup tool with a packer for isolating a zone in the well to be fractured, according to one embodiment of the present disclosure.

Figure 17 shows a cross-sectional view of a ported wellbore completion according to one embodiment of the present disclosure.

18 shows a cross-sectional view of a bottom hole assembly secured to a portion of the ported borehole completion of FIG. 17 with the liner of the ported borehole completion in a closed position.

19 shows a cross-sectional view of a bottomhole assembly secured to a portion of the ported borehole completion of FIG. 17 with the liner of the ported borehole completion in an open position.

Figure 20 shows a cross-sectional view of a wellbore completion according to one embodiment of the present disclosure.

21 shows a cross-sectional view of a wellbore completion including a hydraulic blasting perforator, according to one embodiment of the present disclosure.

While the disclosure is susceptible to various modifications and alternative forms, particular embodiments are shown by way of example in the drawings and will be described in detail herein. However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed. On the contrary, the invention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the invention as defined by the appended claims.

detailed description

Figure 1 illustrates a portion of a wellbore completion 100 according to one embodiment of the present disclosure. The wellbore completion 100 includes a bottom hole assembly (“BHA”) 102 inside a casing 104 . Any suitable BHA can be used. In one embodiment, the BHA 102 may be designed for fracturing in multi-zone oil and gas wells. An example of a suitable BHA is disclosed in co-pending U.S. Patent Application No. 12/626,006, filed November 25, 2009, by John Edward Ravensbergen, entitled COILEDTUBING BOTTOM HOLE ASSEMBLY WITH PACKER ANDANCHOR ASSEMBLY, the disclosure of which is via References are hereby incorporated in their entirety.

As shown more clearly in FIGS. 2 and 3 , casing 104 may include multiple casing sections 106A, 106B, and 106C that may be connected by one or more couplings, such as couplings 108 and 110 . Casing sections 106A, 106B, and/or 106C may be pup joints, approximately 6 feet in length of casing section, which may be configured to assist in properly positioning the BHA within desired regions of the wellbore. Collar 108 may be any suitable collar. Examples of couplings for connecting casing sections are known in the art. In one embodiment, the collar 108 may include two internally threaded portions for connection to the externally threaded ends of the casing section 106 .

A perspective view of a collar 110 according to one embodiment of the present disclosure is shown in FIG. 4 . The collar 110 may include one or more frac ports 112 and one or more valve vents 114 . The frac port 112 may intersect a valve bore 118 , which may be positioned longitudinally in the centralizer 116 . A plug 128 may be positioned in the valve bore 118 to prevent or reduce unwanted upward flow of fluid through the valve bore 118 . In one embodiment, the inner diameter 113 (shown in FIG. 2 ) of the collar 110 may be approximately the same as or larger than the inner diameter of the sleeve 104 . As such, the annulus between collar 110 and BHA 102 is not significantly restricted. In other embodiments, the inner diameter of the collar 110 may be smaller than the inner diameter of the sleeve 104 . Collar 110 may be connected to casing section 106 by any suitable mechanism. In one embodiment, the collar 110 may include two internally threaded portions for connection to the externally threaded ends of the casing sections 106B and 106C.

As shown more clearly in FIG. 5 , the frac ports 112 may be positioned throughout the centralizer 116 , which may allow the frac ports 112 to be located relatively close to the formation. Where the casing is cemented in the wellbore, this may increase the likelihood that the frac port 112 will pass through or nearly pass through the cement.

A valve 120 for controlling fluid flow through the frac port 112 is positioned in the valve bore 118 of the centralizer 116 . When these valves 120 are in the closed position, as shown in FIG. 6 , they prevent or reduce the flow of fluid through the frac ports 112 .

Valve 120 may include one or more seals to reduce leakage. Any suitable seal can be used. One example of a suitable seal 122 is shown in FIG. 6 . Seal 122 may be configured to extend around frac port 112 when valve 120 is in the closed position. The seal 122 may include a ring 122A on one end that fits around the circumference of the valve 120 and a circular portion 122B on the other end that extends only around a portion of said valve 120 . This structure can provide the desired sealing effect and is easy to manufacture.

The shear pin 124 can be used during installation to hold the valve 120 in the closed position and reduce the possibility of the valve 120 opening prematurely. The shear pin 124 may be designed such that when it is sheared, a portion of the pin 124 remains within the wall of the collar 110 and protrudes into the groove 126 of the valve 120 . This enables the sheared portion of the pin 124 to act as a guide to facilitate proper positioning of the seal 122 relative to the frac port 112 by maintaining the valve 120 in the desired orientation. In FIG. 2 the shear pin 124 is shown as a guide, which shows the valve 120 in the open position.

Collar 110 may be connected to the casing section in any suitable manner. In one embodiment, the collar 110 may include two internally threaded portions for connection to the externally threaded end of the casing section 106 , as shown in FIG. 2 .

As also shown in FIG. 2 , a packer 130 may be positioned in the casing between the frac port 112 and the valve vent 114 . When the packer 130 is actuated, it seals against the inner diameter of the collar 110 to prevent or reduce fluid flow further down the wellbore annulus. Therefore, when the fluid flows from the surface to the bottom hole in the annulus between the well casing 104 and the BHA 102 , a pressure differential is formed on both sides of the packer between the fracturing port 112 and the valve vent 114 . This pressure differential can be used to open the valve 120 .

Packer 130 may be positioned in the desired location within collar 110 using any suitable technique. One exemplary technique shown in FIG. 3 uses a locking pawl 132 that may be configured to enter a recess 143 between sleeve portions 106A and 106B. As shown in FIG. 1 , locking pawl 132 may be part of BHA 102 . The length of casing portion 106B may then be selected to position collar 110 a desired distance from recess 134 so that packer 130 may be positioned between frac port 112 and valve vent 114 . During installation, a well operator may install the BHA 102 by lowering the locking pawl through the recess 134 and then lifting the BHA 102 upward until the locking pawl 132 enters the recess 134 . The additional resistance to pulling the locking pawl 132 out of the recess 134 can be detected at the surface and allows the well operator to tell when the BHA 102 is properly positioned in the casing. This may enable a well operator to position packer 130 relative to standard collar 108 , which may be the next lowest collar relative to collar 110 .

Casing 104 may be installed after drilling of the oil and gas well as part of well completion 100 . In one embodiment, casing 104 including one or more collars 110 may be cemented in place in the wellbore. FIG. 1 shows cement 105 flowing into the space between the outer diameter of casing 104 and the inner diameter of wellbore 107 . The technique of cement positioning sleeves is well known in the art. In another embodiment, the casing 104 and collar 110 may be installed in the wellbore using an open hole packer device instead of cement, the packer 111 being positioned between the inner diameter of the wellbore 107 and the outer diameter of the casing 104 , as shown in Figure 8. Such open hole packer completions are well known in the art and one of ordinary skill in the art can readily apply the couplings of the present disclosure to open hole packer type completions.

Collar 110 may be positioned anywhere in the casing that requires a port for fracturing. For example, it is noted that while a standard collar 108 is shown as part of the casing, the collar 108 could be replaced by a second collar 110 . In one embodiment, a collar 110 of the present disclosure may be positioned in each zone in a multi-zone well.

During cementing, the casing is run in and the cement fills the annulus between the casing 104 and the formation of the oil and gas well. Where the valve 120 is positioned in a centralizer, there may be a slight indentation 136 between the outer diameter of the centralizer 116 and the outer diameter of the valve 120 , as shown in FIG. 5 . It may be possible to fill the recess 136 with cement during positioning with cement. Thus, there may be a thin layer of cement that will have to be penetrated before fluid flows through the valve 120 . Alternatively, the recess 136 may not be filled with cement. In one embodiment, the recess 136 may be filled with grease, cement inhibiting grease, or other substance prior to cementing in place in order to reduce the likelihood of the recess 136 being filled with cement.

A potential advantage of the collar design of FIG. 4 is that an open valve 120 moves fluid volume from valve bore 118 through valve vent 114 into the annulus between bushing 106 and BHA 102 . Therefore, all the moving volume that occurs when the valve 120 is opened is inside the completion. This enables the space between the wellbore and the outer diameter of the casing 106 to be filled with, for example, cement without necessarily providing space outside the collar for the fluid volume to move when the valve 120 is open.

Another possible advantage of the collar design of FIG. 4 is the possibility of little or no pressure differential between the valve vent 114 of the collar 110 and the frac port 112 until between the frac port 112 and the valve. The inside diameter of the collar is sealed between the vent holes 114 . This means that in multi-zone wells with multiple collars 110, the operator can control which frac port to open by positioning sealing mechanisms such as packers 130 where desired without worrying about other frac ports in the well. Other frac ports at the location could be inadvertently opened.

The couplings of the present disclosure may be used in any type of oil and gas well. Examples of well types in which these couplings may be used include horizontal wells, vertical wells, and deviated wells.

The completion assembly shown above in connection with FIGS. 1-3 is for an annulus fracturing technique in which fracturing fluid is pumped down the wellbore annulus between oil and gas well casing 104 and BHA 102 . However, the collar 110 of the present disclosure may also be used in other types of fracturing techniques.

One such fracturing technique is shown in Figure 7 where a coiled tubing string is used with a spanning cup tool having packers 140A, 140B for isolating the region of the well to be fractured. As shown in FIG. 7 , a packer 140B may be positioned between the frac port 112 and the valve vent 114 . This enables the valve 120 to be opened by creating a pressure differential between the frac port 112 and the valve vent 114 when the pressure in the region between the packers 140A, 140B in the wellbore increases. The pressure increase can be achieved by flowing fluid down the coiled tubing string at a suitable pressure for opening the valve 120 . The fluid used to open valve 120 may be fracturing fluid or another suitable fluid. After the valve 120 is opened, a fracturing fluid (not shown) may be pumped downhole through the coiled tubing string and into the annulus through the holes 144 and then into the formation through the fracturing ports 112 . A potential advantage of the coiled tubing string/spanning cup tool of Figure 7 is that any frac sand used during the fracturing step can be isolated from the remainder of the wellbore annulus between packers 140A and 140B.

A method of performing multi-zone fracturing using the collar 110 of the present disclosure will now be described. The method may include running casing 104 and collar 110 into the wellbore after drilling the wellbore. Casing 104 and collar 110 may be set in the wellbore as discussed above by filling cement or using a packer of an open hole packer type assembly. After the casing is placed in the wellbore, the BHA 102 connected to the end of the coiled tubing string can be run into the well. In one embodiment, the BHA 102 may initially extend to or near the bottom of the well. During run-down, the locking pawl 132 ( FIG. 3 ) is configured to have a profile that does not fully engage and/or easily slides over the recess 134 . For example, the locking pawls 132 may be provided with a gentle angle 131 on the side facing the bottom of the well so that they can more easily slide through the recesses 134 with little axial force when running downhole.

After the BHA 102 has been run to the desired depth, the well operator can begin pulling the tubing string and BHA 102 up toward the surface. The locking pawl 132 may be profiled to engage the recess 134 at a steep angle 133 on the top of the locking pawl 132, resulting in increased axial force during the upward pull when attempting to pull the locking pawl 132 out of the recess. As discussed above, this increased resistance allows the well operator to determine the proper location in the well to place the packer 130 . It is generally known in the industry to profile the locking pawl 132 to provide reduced resistance to running into a well and increased resistance to pulling out of a well. After the packer 130 is positioned at the desired location, the packer 130 can then be actuated to seal the well annulus between the BHA 102 and the desired collar 110 between the frac port 112 and the valve vent 114 . Empty seal.

After sealing the well annulus at the desired collar 110, the pressure of the well annulus can be raised from the surface to a pressure sufficient to open the valve 120. A suitable pressure range may be, for example, from about 100 psi to about 10,000 psi, such as about 500 psi to about 1000 psi, 1500 psi or greater. The collar 110 is designed so that all frac ports 112 in the collar can be opened. In one embodiment, the pressure to open the frac ports 112 may be set below the frac pressure. This enables the frac pressure, and thus the frac process itself, to ensure that all frac ports 112 are opened. However, it is conceivable that in some circumstances it may not be possible to open all of the frac ports 112 . This can happen due to, for example, a malfunction or the frac ports being clogged with cement. After the frac ports 112 are opened, fluid may be pumped through the frac ports 112 into the well formation. The fracturing process can be initiated and fracturing fluid can be pumped down the wellbore into the formation. Depending on the fracturing technique used, this may include flowing fracturing fluid down the wellbore annulus, such as in the embodiments of FIGS. 1-3 . Alternatively, the fracturing fluid may be flowed down the tubing string of the coiled tubing string, as in the embodiment of FIG. 7 . Fracturing sand, such as mortar, may be used in the process if desired. Frac sand can fill fractures and keep them open after fracking stops. Once the final volume of frac sand reaches the formation, the frac treatment is generally terminated. The displacement fluid is used to push the frac sand down the wellbore into the formation.

The prefluid is the fluid that is pumped prior to pumping the frac sand into the formation. The prefluid ensures that sufficient fracture width exists before the frac sand reaches the formation. If a ported collar assembly is used, the displacement fluid may be the lead fluid for subsequent processing. As a result, fluid consumption is reduced.

In multi-zone wells, the above fracturing process may be repeated for each zone of the well. Thus, the BHA 102 can be seated in the next collar 110, the packer can be activated, the frac port 112 can be opened and the frac process performed. This process can be repeated for each zone from the bottom of the wellbore up. After fracturing, oil may flow from the fracture through the frac port 112 of the collar 110 and into the well.

In an alternative multi-zone embodiment, the fracturing can be done top down or in any order. For example, a spanning cup tool such as that disclosed in FIG. 7 may be used to isolate above and below the well region by techniques known in the art. The frac port 112 may then be opened by increasing the pressure through the coiled tubing string, similar to that discussed above. The first zone is then fractured, also in a manner similar to that described above. The spanning cup tool can then be moved from the surface to a second area and the process repeated. Because the spanning cup tool can isolate the collar from the collars above and below it, the spanning cup tool allows fracturing of any zone along the wellbore and eliminates the need to initiate fracturing in the lowermost zone and Increase the need for casing.

The design of the collar 110 of the present disclosure allows the valve 120 to close after it has opened. This is beneficial in the event that certain zones in a multi-zone well begin to produce water or other unwanted fluids. If these areas where water is produced can be located, the collars associated with these areas can be closed to prevent unwanted fluid flow from that area. This can be done by isolating the valve vent 114 and then increasing the pressure to force the valve 120 closed. For example, a spanning cup tool similar to the embodiment of FIG. On the side of the valve vent 114 remote from the packer 140A. When the region between these packers is pressurized, a high pressure builds up at the valve vent 114 which forces the valve 120 to close.

Erosion of the frac port 112 by fracturing and other fluids may prevent the valve 120 from sealing effectively against fluid flow even with the frac port 112 closed. However, the design of the collar 110 of the present disclosure that allows multiple frac ports to open in a single collar may help reduce erosion compared to designs where only a single frac port is opened. This is because multiple frac ports can provide a relatively large flow area, effectively reducing the pressure differential of the fluid across the frac ports during frac. A reduced pressure differential can result in a desired reduction in erosion.

Figure 10 shows a portion of a wellbore completion 200 according to one embodiment of the present disclosure. The wellbore completion includes casing sections 206a, 206b connected to a collar assembly 210 hereafter referred to as collar 210 . FIG. 11 shows an enlarged view of the upper portion of the collar 210 , and FIG. 12 shows an enlarged view of the lower portion of the collar 210 . The collar 210 shown in FIG. 11 includes a mandrel 209 which may include a length of casing, a valve housing 203 and a vent housing 201 . A valve, such as a bushing 220 , is positioned within the annulus 218 between the mandrel 209 and the valve housing 203 . Bushing 220 is movable between an open position (shown in FIG. 10 ) that allows communication between the inner diameter of mandrel 209 and outer frac port 212B through inner frac port 212A located in mandrel 209 . The annulus 218A extends around the periphery of the mandrel and communicates with an annulus 218B between the vent housing 201 and the mandrel 209 , which may be referred to as a single annulus 218 . The bushing 220 is movable to a closed position (shown in FIG. 15 ) that prevents fluid communication between the inner frac ports 212A and the outer frac ports 212B, collectively referred to as the frac ports 212 . The bushing 220 effectively seals the annulus 218 into upper portions 218A and 218B, allowing a pressure differential to develop between the two annulus to move the bushing 220 between its open and closed positions. Valve housing 203 may be connected to vent housing 201 using sealing ring 215 . A recess 218C in the mandrel below the seal ring ensures good fluid communication between the upper part 218A and the lower part 218B of the annulus 218 through the seal ring 215 . Alternatively, the valve housing and the vent housing may be a single housing. In this embodiment, the sealing ring to connect the two housings and the recess in the mandrel to provide fluid communication would not be necessary.

Figure 12 shows the lower portion of the vent housing 201 and the mandrel 209 with the annulus 218B between these two elements. A lower nut 228 connects the lower end of the vent housing 201 to the mandrel 209, wherein the sealing element 222 seals the lower portion of the annulus 218B. The mandrel 209 includes a vent hole 214 in communication with an annulus 218 . In one embodiment, a plurality of vent holes 214 are provided around the mandrel 209 . The mandrel may include a plurality of vent holes 214B at locations other than the main vent hole 214 . In operation, each vent hole may be filled with a burst device, such as a burst plug, or cement inhibiting grease to prevent cement or other undesirable substances from entering the annulus 218 . In addition to the burst plug, cement inhibiting grease may be injected into the annulus 218 prior to running the completion into the wellbore to prevent cement from entering the annulus 218 while cementing the completion in the wellbore. The vent housing 201 may include a fill port 227 to assist in injecting grease into the annulus 218 . Preferably, one of the vent holes may be substantially smaller in diameter than the remaining vent holes and does not include a burst plug. After bursting the burst plug, the vent allows a pressure differential to be applied in the annulus 218 to open or close the valve 220, as discussed in detail above. Where cement enters the annulus 218 via the vent 214 , the vent housing may include a second vent 214B closer to the wellhead along the mandrel 209 that may enable communication with the annulus 218 .

FIG. 13 shows the lower portion of the mandrel 209 without the vent housing 201 . Burst plugs 231 have been inserted into vent holes 214, 214B. Preferably, the burst plug is not inserted into the smallest vent hole 214A, which may be about 1/8 inch in diameter. The vent housing 201 is adapted to provide a predetermined distance between the frac port 212 and the vent hole 214 . The vent holes 214 may be approximately two meters from the frac ports to provide sufficient space for the positioning of the packing elements to allow for the application of a pressure differential. Positioning the packing element precisely (within half a meter) in the wellbore is difficult. Furthermore, the position of the collars relative to each other is generally not known precisely, mainly due to errors in measurements taken when installing the completion into the wellbore. The challenge of precisely positioning the packing elements in the wellbore is due to several factors. One factor is the inaccuracy of the equipment used to measure the force exerted on the coiled tubing string as it is pulled from the bore, which can typically produce errors of 1000 lbs of force or more. The casing collar positioning profile (133) of Fig. 1 generally increases the force to pull out of the wellbore by 2000 lbs. Furthermore, the friction between the coiled tubing string and the casing in horizontal oil and gas wells is high and not constant when pulled from the well. As a result, knowing what is responsible for the observed force increases at the surface is difficult. It could be due to a casing collar retainer pulled into the sub, or it could be due to other forces between the coiled tubing string and the completion and/or centralizers. A strategy to improve the possibility of determining the location of the packing element is to use short casing sections, typically two meters long, above and below the collar assembly. Thus, there are three or four joints (depending on the configuration of the coupling) at a known spacing different from the standard casing section, which is typically 13 meters long. Absolute depth measurements relative to the surface or relative to recorded count sheets are no longer required due to the use of short casing sections directly connected to the collar assembly. However, as will be appreciated by those skilled in the art given the teachings of this disclosure, this distance between the frac port and the vent can be varied to accommodate various packing elements or structures to allow the application of a pressure differential.

FIG. 9 illustrates a portion of a wellbore completion 200 including a BHA inside a casing composed of casing sections 206 via a plurality of collars, such as collars, according to one embodiment of the present disclosure. 210 are connected together. The collar 210 in this embodiment is composed of the mandrel 209 , the valve housing 203 and the vent housing 201 . A valve, such as bushing 220 , is positioned within annulus 218 between mandrel 209 and valve housing 203 . The bushing 220 is movable between an open position (shown in FIG. 10 ) that allows communication between the inner diameter of the mandrel 209 and the outer frac port 212B via the inner frac port 212A. The bushing 220 includes a collet 221 configured to engage a recess 223 (shown in FIG. 15 ) on the mandrel 209 to selectively retain the bushing 220 in its open position. Sealing element 222 may be used to provide a seal between valve housing 203 , spindle 209 and bushing 220 . Valve housing 203 may include one or more fill ports 217 that allow for the injection of grease or other cement-inhibiting substances into annulus 218 for use in cementing to position completion 200 in the wellbore. Prevent cement from entering.

Figure 15 shows a cross-sectional view of the upper portion of the collar 210 with the bushing 220 in the closed position. Shear pin 224 selectively maintains bushing 220 in the closed position. The shear pin 224 may be used to hold the bushing 220 in the closed position during installation and reduce the possibility of the bushing 220 (or valve 120 ) opening prematurely. As will be appreciated by those of ordinary skill in the art, the shear pin 224 may be adapted to shear and release the bushing 220 upon application of a predetermined pressure differential. Mandrel 209 may include one or more ports 230 positioned on the uphole side of closed liner 220 to assist in applying a pressure differential over liner 220 into annulus 218A when moving liner 220 to the open position. After opening the liner and fracturing the wellbore, the liner 220 may be moved back to the closed position upon application of a pressure differential as discussed above. Ports 230 on the mandrel 209 may allow fluid to flow out of the annulus 218A as it passes through the frac ports 212 as the liner 220 moves to the closed position. The mandrel 209 may include a recess 229 adapted to mate with the collet 221, which selectively holds the bushing 220 in the closed position until another pressure differential is applied. In the illustrated embodiment, the bushing 220 surrounds the entire periphery of the mandrel 209 . Alternatively, multiple liners may be used to selectively allow fluid communication with frac ports 212 .

The collar 210 may include one or more inner frac ports 212A, one or more outer frac ports 212B, and one or more vent holes 214 (shown in FIG. 12 ). The outer frac port 212B intersects the annulus 218 and may be positioned in the centralizer 216 along the outside of the collar 210 (as shown in FIG. 14 ). In one embodiment, the inner diameter of the collar 210 may be approximately the same as or larger than the inner diameter of the casing. In this way, the annulus between collar 210 and the BHA is not significantly restricted. One potential challenge of this process is the reliable use of packers between casing sections, which are typically used in casings where there may be large variations in internal diameter. The use of a ported collar 210 can reduce this potential problem because the ported collar 210 can be manufactured with less variation in inner diameter and with a less oval shape than typical casings. These improvements provide improved reliability for forming a proper seal within collar 210 with typical packers. In other embodiments, the inner diameter of the collar 210 may be smaller than the inner diameter of the sleeve. However, the inner diameter of the collar 210 may still be within the tolerance range of the casing inner diameter. Collar 210 may be connected to casing section 106 by any suitable mechanism. In one embodiment, the collar 210 may include two internally threaded portions for connection to the externally threaded ends of the casing sections 206b and 206c.

As shown more clearly in FIG. 14 , external frac ports 212B may be positioned throughout centralizer 216 , which enables positioning of external frac ports 212B relatively close to formation 107 . In cases where cement is used to position the casing into the wellbore, this may increase the chance that the frac port 112 will pass through, or nearly pass through, the cement 105 . As shown in Figure 14, one or more of the centralizers 216 may be in direct contact with the open hole formation 107, which may be on the underside in a horizontal well as would be appreciated by one of ordinary skill in the art given the teachings of this disclosure Centralizer 216. A valve, such as bushing 220, may be positioned in the annulus in fluid communication with inner frac port 212A and outer frac port 212B. The annulus 218 may be between the mandrel 209 and the outer valve housing 203 . When the liner 220 is in the closed position, as shown in FIG. 15 , it prevents or reduces the flow of fluid through the frac port 112 .

As shown in FIG. 9 , a packer 230 may be positioned in the casing between the frac port 212 and the valve vent 214 . When the packer 230 is actuated, it seals against the inner diameter of the collar 210 to prevent or reduce fluid flow further down the wellbore annulus. Therefore, when the fluid flows from the surface to the bottom hole in the annulus between the oil and gas well casing 104 and the BHA, a pressure differential is formed between the fracturing port 212 and the valve vent hole 214 on both sides of the packer. This pressure differential can be used to open the valve 220 . The use of the packer in Figure 9 to create a pressure differential is for illustration purposes, as a variety of tools and techniques can be used to create a pressure differential to open and/or close the valve, as will be appreciated by those of ordinary skill in the art . For example, a rotary jet tool may be inserted into the casing and directed toward the valve vent to create the pressure differential required to close the valve.

As discussed above, in cementing in place, the casing is run in and the cement is pumped down the center hole of the casing and out the end of the casing 104, filling the gap between the casing 104 and the well formation. the annulus in between. To prevent ingress of cement and/or fluids used in cement setting, grease or other substances may be injected into annulus 218 of collar 210 prior to running the casing into the wellbore. A burst plug may be inserted into valve vent 214 and grease may be injected into the annulus through injection ports in valve housing 203 and vent housing 201 . The injection port can then be plugged.

Figure 16 shows one technique for opening the liner 220 to fracture the formation. The coiled tubing string is used with a spanning cup tool having packers 140A, 140B for isolating the zone to be fractured in the oil and gas well. FIG. 16 shows only a portion of a spanning cup tool that may be used with the collar assembly of the present disclosure. As shown in FIG. 16 , downhole packer 140B may be positioned between frac port 212 and valve vent 214 (shown in FIG. 12 ). This can open the liner 220 by creating a pressure differential between the frac port 212 and the valve vent 214 when the pressure in the region between the packers 140A, 140B in the wellbore increases. The pressure increase may be achieved by flowing fluid down the coiled tubing string and out the bore 144 at a suitable pressure for opening the valve 220 . The fluid used to open valve 220 may be a fracturing fluid. A potential advantage of the coiled tubing string/spanning cup tool assembly of Figure 16 is that any frac sand used during the fracturing step can be isolated from the remainder of the annulus between packers 140A and 140B. In one embodiment, the liner 220 may be adapted to open at a predetermined pressure differential above the desired fracturing pressure. Thus, energy can be stored within the coiled tubing string prior to opening the liner 220 and the formation can be fractured very quickly after the frac port 212 is opened.

A multi-zone fracturing method using the collar 210 of the present disclosure will now be described. The method may include running casing 104 and collar 210 into the wellbore after drilling the wellbore. Casing 104 and collar 210 may be set in the wellbore by a packer as discussed above by packing with cement or using an open hole packer type assembly. After the casing is placed in the wellbore, the BHA connected to the end of the coiled tubing string or joint may be run into the well. In one embodiment, the BHA 102 may initially be run downhole at or near the bottom. During run-down, the locking pawl 132 ( FIG. 3 ) is configured to have a profile that does not fully engage and/or easily slides over the recess 134 . For example, the locking pawls 132 may be provided with a gentle angle 131 on the side facing the bottom of the well so that they can more easily slide through the recesses 134 with little axial force when running downhole.

After the BHA is lowered to the desired depth, the well operator can begin pulling the coiled tubing string and BHA up toward the surface. The locking pawl 132 may be profiled to engage the recess 134 at a steep angle 133 on the top of the locking pawl 132, resulting in increased axial force during the upward pull when attempting to pull the locking pawl 132 out of the recess. As discussed above, this increased resistance allows the well operator to determine the proper location in the well to place the packer 230 . It is generally known in the industry to profile the locking pawl 132 to provide reduced resistance to running into the well and increased resistance to exiting the well. After the packer 230 is positioned at the desired location, the packer 230 can then be actuated to seal the oil and gas well annulus between the BHA and the desired collar 210 between the frac port 212 and the valve vent 214 Empty seal.

After sealing the well annulus at the desired collar 210 , the pressure of the well annulus can be raised from the surface to a pressure sufficient to open the valve 220 . A suitable pressure range may be, for example, from about 100 psi to about 10,000 psi, such as about 500 psi to about 1000 psi, 1500 psi or greater. As discussed above, suitable pressures may be adapted to exceed desired fracturing pressures to assist rapid fracturing of the formation.

After the frac port 212 is opened, fluid may be pumped through the frac port 212 into the well formation. The fracturing process may be initiated and fracturing fluid may be pumped down the wellbore to fracture the formation. Fracturing sand, such as mortar, can be used in the process if desired. The fracking sand can fill the fractures and keep them open after the fracking has stopped. After fracturing, the BHA can be used to remove any unwanted frac sand/frac fluid from the wellbore.

In multi-zone wells, the above fracturing process may be repeated for each zone of the well. Thus, the BHA can be seated in the next collar 210, the packer can be actuated, the frac port 212 can be opened and the frac process performed. This process can be repeated for each zone from the bottom of the wellbore up. After fracturing, oil may flow from the fracture through the frac port 212 of the collar 210 and into the well. When using a BHA as shown in Figure 1, the first treatment may be placed at the bottom of the well and each subsequent treatment may be higher up in the well in an incremental manner. Fracturing treatments for each zone can be completed in a single trip of the BHA, requiring minimal time between zone fracturing. A collar assembly of the present disclosure positioned in a region above the current treatment is exposed to the current treatment wellbore pressure. This pressure can sometimes be limited by the pressure rating of the casing. However, there is no risk of the valves of these coupling assemblies opening prematurely because the pressures on both sides of the valves are balanced. The valve of the present disclosure can only be opened with a pressure differential between the frac port and the valve vent. Furthermore, the present disclosure provides efficient use of fluids during fracturing because the displacement fluid for the current zone being fractured can be used as a lead fluid for the next zone to be treated.

The design of the collar 210 of the present disclosure enables the valve 220 to be closed after opening. This is beneficial in the event that certain zones in a multi-zone well start producing water or some other unwanted fluid. If these areas where water is produced can be located, the collars associated with these areas can be closed to prevent unwanted fluid flow from that area. This can be done by isolating the valve vent 214 and then increasing the pressure to force the valve 120 closed. For example, a straddling cup tool similar to the embodiment of FIG. On the side of the valve vent 214 facing away from the packer 140A. When the region between these packers is pressurized, a high pressure builds up at the valve vent 214 which forces the valve 220 to close. As discussed above, the bushing 220 may include a collet 221 that helps retain the bushing 220 in its closed position.

17-19 illustrate a portion of a wellbore completion 300 according to one embodiment of the present disclosure. Wellbore completion 300 may include a bottom hole assembly BHA 302 positioned inside the casing. The bushing may include segments and connectors joined together, such as nipple 306, adapters 315 and 317, and ported housing 310, as well as conventional bushings, as would be appreciated by one of ordinary skill in the art given the teachings of this disclosure. realized.

FIG. 17 shows the nipple 306 connected to one end of the ported housing 310 through an upper adapter 315 . The other end of the ported housing 310 is connected to another nipple 306 via a lower adapter 317 . The pup joint 306 may be connected to conventional casing to form part of a casing string. The segments of the casing string are fastened together via threads 343 . The shown connections via threads and configurations of the sleeve segments are for illustration purposes, as different connections and any suitable configurations may be used within the scope of the present disclosure. For example, ported housing 310 may be connected directly to sub-section 306 without using adapters 315 , 317 .

Ported housing 310 includes at least one frac port 312 that allows fluid communication between the interior and exterior of housing 310 . Bushing 320 may be slidably connected to an inner surface of housing 310 . In an initial position, as shown in FIG. 17 , bushing 320 may be positioned such that seal 322 prevents fluid communication through port 312 . A shearable device 324 may be used to selectively retain the liner 320 in the initial closed position. The shearable device 324 may be a shear pin, a crush ring, or other device adapted to selectively release the bushing 320 from the housing 310 upon application of a predetermined force, which may be applied by hydraulic force, as follows discussed in detail.

FIG. 18 shows the BHA 302 connected to a coiled tubing string 342 that has been inserted into the casing and positioned within the ported housing 310 . Casing collar locators can be used to position the BHA301 in the desired position within the casing. For example, lower adapter 317 may include profile 333 adapted to engage profile 332 of a casing collar locator to properly position BHA 302 within a particular ported housing 310 along a string of casing.

The BHA 302 includes a packer 330 that can be actuated to seal the annulus between the exterior of the BHA 302 and the inner diameter of the liner 320 of the ported housing 310 . The BHA 302 also includes a mount 350 that can be set against the bushing 320 . Pressure applied down the coiled tubing string is used to actuate the fixture 350 and set it against the liner 302 and for setting the packer 330 . A potential advantage of this embodiment of the BHA 302 is that the BHA 302 can be set within the casing 310 of the casing string without using the J-shape of the BHA 302 that requires downward movement, upward movement, and then downward movement of the coiled tubing string 342 to set the BHA 302. slot. This repeated cyclic up and down motion of the set BHA 302 of the coiled tubing string 342 may result in faster failure of the coiled tubing string 302 . In comparison, the current implementation of the BHA 302 and ported housing 310 and liner 320 provides less movement of the coiled tubing string 342 . After opening the liner 320, as discussed below, the BHA 302 can be released, the casing string moved up to the next desired zone, and set within the selected casing 310 without any circulation of the coiled tubing string 342 up and down movement.

After setting fixture 350 to secure BHA 302 to liner 320 and actuating packer 330 , fluid can be pumped down the casing creating a pressure differential across packer 330 . After a predetermined pressure differential is reached, the shearable device 324 will shear, thereby releasing the bushing 320 from the housing 310 . The shearable device 324 may be adapted to shear at a predetermined pressure differential, as will be appreciated by those skilled in the art.

After the shearable device releases the liner 320 from the casing 310, the increased pressure differential across the packer 330 will then move the BHA 302 secured to the liner 320 down the casing. In this way, the bushing 320 can be moved from the closed position shown in FIG. 18 to the open position shown in FIG. 19 . Alternatively, liner 320 may be moved to the open position by applying a downward force to BHA 302 with coiled tubing string 342 or by applying a combination of hydraulic pressure and downward force from coiled tubing string 342 .

After moving to the open position, bushing 320 may be selectively locked into the open position. For example, the bushing 320 may include an expandable device 325, such as a "c" ring or locking pawl, that expands into a recess 326 in the interior of the housing 310 to selectively lock the bushing 320 in the open position. In the open position, there may be fluid communication between the interior of housing 310 and the exterior of housing 310 , allowing treatment and/or stimulation of the well formation proximate port 312 .

A plurality of ported casings 310 with liners 320 may be positioned along the casing section at locations where fracturing is desired. After fracturing is performed using the first ported casing 310 and liner 320, the BHA may be moved to a second ported casing 310 comprising a second liner 320, here at Fracturing is performed at a second location in the oil and gas well. This process can be repeated until the desired fracturing of the oil and gas well is complete.

The use of the BHA 302 in combination with the ported housing 310 and liner 320 may provide an inexpensive system compared to other systems to selectively stimulate and/or treat oil and gas well formations. For example, the configuration of this embodiment may allow the use of various lengths of casings and liners to position multiple ports 312 along the casing string for greater contact with the formation, as desired. Additionally, validation of this embodiment may allow for large internal flow diameters compared to other fracturing/treatment systems.

The processes described here include annular fracturing processes in which fracturing fluid is pumped down the well annulus and coiled tubing string fracturing processes. A potential problem with some annular fracturing processes is that often the volume of the wellbore annulus is greater than the volume of the fluid being processed, especially as stages become smaller and placed closer together. Pumping the slurry may become necessary for subsequent processing to move the currently processed fluid without expending additional fluid or time. As a result, additional process risk may occur because the process of unseating, moving the BHA, and initiating subsequent fracturing is performed with mud already present in the well. Additionally, the process can start and stop mud pumping, which can add operational complexity, increase risk and reduce the quality of the treatment.

Embodiments of the present disclosure that pump process fluid through a coiled tubing string may have the advantage that the coiled tubing string volume is generally smaller than the process fluid volume, thereby requiring no additional time and additional fluid. Furthermore, because the coiled tubing string has a smaller cross-sectional area than the wellbore and coiled tubing string annulus, fluid velocities are generally higher and the frac sand is less likely to break out of solution and remain in the coiled tubing string. This may be beneficial because residual frac sand can interfere with the treatment process. For example, if frac sand is introduced into the treatment too early, when the pad fluid is pumped, the frac sand can break off, preventing fracture width from growing and causing sand to filter. Pumping the treatment fluid down the coiled tubing string can also result in less grit in the wellbore, which can allow for easier movement and improved functionality of the BHA in the coiled tubing string.

Figure 20 illustrates a wellbore completion 400 designed for coiled tubing string fracturing, according to one embodiment of the disclosure. Casing assembly 404 includes a plurality of casing sections 406A and 406B and at least one collar 410 positioned to connect the casing sections together, similar to other embodiments described herein. The at least one collar 410 includes at least one frac port 412 configured to provide fluid communication between an outer surface of the collar and an internal flow path of the casing and collar assembly. For example, the collar can be any collar that includes a frac port as described herein. If desired, the collar may include multiple centralizers, such as shown in Figures 4 and 5, with at least one frac port extending through the centralizers. By using a collar including a fracturing port in each zone of a multi-zone well, the need to perforate all zones prior to fracturing can be reduced or eliminated. In another embodiment, the collar may be similar to that shown in Figures 17-19, which includes a ported collar 310 and a bushing 320 as described above.

Coiled tubing string 442 is positioned in casing assembly 404 . Coiled tubing string 442 includes internal flow paths for carrying fluids to and from the surface. An annulus 450 is formed between coiled tubing string 442 and casing assembly 404 . The bottom hole assembly 402 is connected to the coiled tubing string. The bottom hole assembly 402 includes a frac hole 444 configured to provide fluid communication between an internal flow path of a coiled tubing string 442 and an annulus 450 . As shown, multiple frac holes may be used. The frac holes may be large enough so that increased flow rates can be obtained without undue pressure drops as the treatment fluid exits the BHA. Suitable hole sizes range, for example, from about 0.5 inches to about 0.75 inches wide and from about 2 inches to about 4 inches long. In addition, the size of the holes may vary depending on the number of holes.

BHA 402 also includes packer 430 . Any suitable packer can be used. Examples of suitable packers include those available from Baker Hughes, Inc. of Houston, Texas for use in the SURESET ^™ BHA, or available from NCS® of SPRING, Texas for use in the MONGOOSE ^™ BHA. Packer acquired by Energy Service.

In one embodiment, the second packer is not positioned in the annulus above the first packer 430 - which would be the case if the packer was a straddle cup tool, such as the straddle in Figure 7 Cup tools. The spanning cup tool can be used to isolate each stage while pumping process fluid through the coiled tubing string, typically perforating the different stages before the fracturing operation begins. While spanning cup tools have certain benefits, the problem with using spanning cup tools is that circulating the treatment fluid through the spanning cup tool's upper cup or packer to remove excess frac sand becomes difficulty. In addition, spanning cup tool packers have a large outer diameter and are prone to plugging when working in mud. The spanning cup tool also relies on a good pouring cement job to isolate each stage. Because the casing above the spanning cup tool is not exposed to the fracturing pressure, there is a risk that the casing will collapse or that treatment fluid will flow out of the casing at the next set of perforations above the current treatment location.

The packer used in the embodiment shown in Figure 20 may have a relatively small diameter compared to a straddling cup tool and thus be less likely to plug. In one embodiment, the outer diameter of the packer may be, for example, about 0.25 inches to about 0.75 inches smaller than the inner diameter of the casing. Furthermore, because no straddling cup tool is used in this embodiment, the wellbore annulus above the packer is pressurized throughout the fracturing process, which can reduce reliance on cement for zone isolation.

Referring to Figure 20, when running the BHA 402 into the casing assembly 404 on the coiled tubing string 442, the packer 430 may be positioned adjacent to the collar 410 to allow contact with the collar 410 as the packer is expanded, thereby The portion of annulus 450 above packer 430 is isolated from the portion of annulus 450 below packer 430 . As such, fluid flowing down the coiled tubing string and into annulus 450 via bore 444 may create a pressure differential across packer 430 after packer expansion, similar to that described above with respect to FIG. 2 .

FIG. 21 shows another embodiment of the present disclosure which is similar to that of FIG. 20 except that the BHA 402 includes a hydraulic blast perforator 452 . Hydroblasting perforators are generally known in the art. The bottom hole assembly is configured to provide fluid flow isolation in the internal flow path between the hydroblast perforator 452 and the frac hole 444, as will be discussed in detail below. A hydroblast perforator can be used as a backup to the frac port in the collar. If the liner in the collar does not open, or if the formation near the liner is too hard to break under the frac pressure, the BHA can be moved a few feet and the casing can be perforated. A fracturing treatment may then be applied through the newly formed perforations in the casing.

Returning again to FIG. 20 , the present disclosure also relates to a method for completing a hydrocarbon wellbore. The method includes running a coiled tubing string 442 into casing assembly 404 . Collar 410 of casing assembly 404 includes a plurality of holes, such as first frac port 412 and valve vent hole 414 .

As discussed above, bottom hole assembly 402 connected to coiled tubing string 442 includes packer 430 . During coiled tubing string run-in, packer 430 may be positioned such that when packer 430 is actuated, packer 430 contacts at least one collar 410 to seal the portion of annulus 450 above packer 430 Isolated from the portion of the annulus 450 below the packer 430 . This enables fluid pumped down the coiled tubing string 442 to create a pressure differential across the packer 430 that can open the frac ports 412 .

Optionally, the liner can be designed such that mechanical force can be used in combination with fluid pressure to open and/or close the frac port 412 . For example, a string of coiled tubing may be used to apply pressure to the liner, similar to that described above with respect to FIGS. 18 and 19 .

After the frac ports 412 are opened, the well formation may then be fractured by flowing a frac fluid through the frac ports 412 . This process can be repeated multiple times to complete multi-zone fracturing.

In embodiments where the bottom hole assembly 402 includes a hydroblast perforator 452, the method may also include isolating fluid flow between the hydroblast perforator and the fractured orifice. This can be accomplished by any suitable technique. For example, bottom hole assembly 402 may include a seating profile, such as a ball seat (not shown), that constrains the diameter of the internal flow path between hydroblasting gun 452 and bore 444 . A ball, dart, or other device (not shown) used to plug the flow path of the coiled tubing string may then be pumped down the coiled tubing string so that the device sits on the hydroblast perforator and the fracturing between the holes, thereby isolating the hydroblasting gun 452 from the holes 444. Such seating profiles and ball or dart-like component systems are generally known in the art.

Plugging the flow path of the coiled tubing string allows the abrasive slurry to be pumped down the coiled tubing string and ejected from the hydraulic blasting perforating tool. After the operation of the hydroblast perforator is complete, the flow in the coiled tubing string and BHA 402 may be reversed to lift the ball to the surface, thereby restoring fluid flow from the coiled tubing string through hole 444 . As an alternative to the sit profile and ball or dart style component system, various other mechanisms may be used to isolate the hydroblasting gun 452 from the hole 444, as will be appreciated by those of ordinary skill in the art given the teachings of this disclosure. of.

While various embodiments have been shown and described, the disclosure is not so limited and it will be understood to include all such modifications and variations as would be apparent to those skilled in the art.

Claims (21)

1. a wellhole completion, including:

Thimble assembly, it includes multiple casing section and is positioned to connect at least the one of these casing sections Individual box cupling, at least one box cupling wherein said includes the tubular body with internal flow path and joins At least the one of the fluid communication being set between outer surface and the described internal flow path of offer box cupling Individual pressure break port；

The one section of coiled tubing being positioned in thimble assembly, coiled tubing includes internal flow path, Between coiled tubing and thimble assembly, wherein form annular space；

Being connected to the BHA of coiled tubing, this BHA includes: be configured to The pressure break hole of the fluid communication between internal flow path and the described annular space of offer coiled tubing； And packer, it is positioned to when this packer is expanded allow to connect with at least one box cupling described Touch, wherein said packer can by the annular space below the annular space above packer and packer every Described pressure break hole can be flowed out from, in order to the fluid flowed downward along coiled tubing so as Packer both sides form pressure reduction, thus open pressure break port.

Wellhole completion the most according to claim 1, wherein said BHA also wraps Including sand jet perforator, this BHA is configured to realize sand jet perforator And the fluid flow isolation between the pressure break hole in coiled tubing.

Wellhole completion the most according to claim 1, wherein said BHA does not wraps Include sand jet perforator.

Wellhole completion the most according to claim 1, wherein said packer is not across formula Packer.

Wellhole completion the most according to claim 1, the wherein ring above the first packer Do not position the second packer in the air.

Wellhole completion the most according to claim 1, wherein said box cupling also includes:

At least one valve opening intersected with pressure break port in described box cupling；

It is positioned to provide at least one ventilation of the fluid communication between valve opening and internal flow path Hole；And

At least one valve for opening and closing pressure break port being positioned in valve opening, described valve It is configured to when forming pressure reduction between pressure break port and valve passage open.

Wellhole completion the most according to claim 6, at least one valve wherein said is can The lining of movement in valve opening.

Wellhole completion the most according to claim 7, wherein said valve is longitudinal rod.

Wellhole completion the most according to claim 6, also include from tubular body stretch out multiple Centralizer.

Wellhole completion the most according to claim 9, at least one pressure break end wherein said Mouth runs through described centralizer and extends.

11. wellhole completions according to claim 1, wherein said box cupling also includes sliding Being connected to the lining of the inner surface of tubular body, this lining can be at primary importance and second dynamicly Regulating between putting, this lining is configured to stop the fluid connection by pressure break port in primary importance Pass to and in the second position, allow the fluid communication by pressure break port.

12. wellhole completions according to claim 11, wherein said BHA is also Including being configured to be fixed to this BHA the fixture of lining.

13. 1 kinds for the method that Hydrocarbon exploitation wellhole is carried out completion, the method bag Include:

By in the thimble assembly delivering to wellhole under coiled tubing, this thimble assembly includes multiple sleeve pipe Section and be positioned to one or more box cuplings of being linked together by these casing sections, wherein said one The first box cupling in individual or multiple box cupling includes the first pressure break port；

The first pressure break end of thimble assembly is opened to apply pressure reduction by coiled tubing pumping fluid Mouthful；And

Pressure break Oil/gas Well stratum is come by making fracturing fluid flow through the first pressure break port；

Wherein, described coiled tubing includes BHA, and this BHA includes envelope Every device and pressure break hole, the method also includes: packer is positioned to allow for described at least one Box cupling contacts；And activate described packer with by annular space part above packer and annular space Part isolation below packer, in order to the fluid flowed downward along coiled tubing can The pressure reduction that can open pressure break port is formed in packer both sides.

14. methods according to claim 13, wherein said first box cupling includes multiple hole, At least one hole in the plurality of hole on first box cupling is the first pressure break port, this first pressure Split and apply pressure reduction between two holes that port is configured through on the first box cupling to beat on an off Close.

15. methods according to claim 13, the wherein annular space above the first packer In not location the second packer.

16. methods according to claim 13, wherein said BHA also includes Sand jet perforator, the method also includes isolating between sand jet perforator and pressure break hole Fluid flows.

17. methods according to claim 16, wherein the step of buffer fluid flowing includes Along coiled tubing pump down ball, described ball sit be placed on sand jet perforator and pressure break hole it Between.

18. methods according to claim 13, also include pumping fluid by coiled tubing The second pressure break port is opened with applying pressure reduction.

19. methods according to claim 18, also include by making fracturing fluid flow through Two pressure break ports come pressure break Oil/gas Well stratum.

20. methods according to claim 13, wherein use mechanical force with force combination Open the first pressure break port.

21. 1 kinds for the method that Hydrocarbon exploitation wellhole is carried out completion, the method bag Include:

By in the thimble assembly delivering to wellhole under coiled tubing, this thimble assembly includes multiple sleeve pipe Section and be positioned to one or more box cuplings of being linked together by these casing sections, wherein said one The first box cupling in individual or multiple box cupling includes the first pressure break port；

The first pressure break end of thimble assembly is opened to apply pressure reduction by coiled tubing pumping fluid Mouthful；And

Pressure break Oil/gas Well stratum, wherein machinery is come by making fracturing fluid flow through the first pressure break port Power and pressure are used in conjunction with opening the first pressure break port.