DOWNHOLE PACKER TOOL ENGAGING AND OPENING PORT SLEEVE UTILIZING HYDRAULIC FORCE OF FRACTURING FLUID

Abstract

A downhole packer tool includes a center mandrel and a packer provided around the center mandrel. The tool further includes sleeve engaging members movable between extended and retracted positions to either engage with a port sleeve or allow the packer tool to pass by the sleeve without engagement. In a run mode of operation, the sleeve engaging members retract toward the center mandrel. In a set mode of operation, a hydraulic force of a fluid flowing through the wellbore in a downhole direction generates an outward force pushing the sleeve engaging members away from the center mandrel such that they engage with an adjacent port sleeve. Once engaged, hydraulic fluid pressure causes the packer to move the sleeve into an open position. While engaged with the sleeve, uphole force applied to the packer tool may also be used to move the sleeve into a closed position in a similar manner.

Description

BACKGROUND OF THE INVENTION

(1) Field of the Invention

The invention pertains generally to fracturing oil and gas wells for hydrocarbon production. More specifically, the invention relates to a downhole packer tool that engages with and opens a port sleeve pre-installed in the wellbore for hydraulic fracturing and enhancing the production of subterranean wells thereof.

(2) Description of the Related Art

Wells are drilled to a depth in order to intersect a series of formations or zones in order to produce hydrocarbons from beneath the earth. Some wells are drilled horizontally through a formation and it is desired to section the wellbore in order to achieve a better stimulation along the length of the horizontal wellbore. The drilled wells are cased and cemented to a planned depth or a portion of the well is left open hole.

Producing formations intersect with the wellbore in order to create a flow path to the surface. Stimulation processes, such as fracking or acidizing are used to increase the flow of hydrocarbons through the formations. The formations may have reduced permeability due to mud and drilling damage or other formation characteristics. In order to increase the flow of hydrocarbons through the formations, it is desirable to treat the formations to increase flow area and permeability. This is done most effectively by setting either open-hole packers or cased-hole packers at intervals along the length of the wellbore or cementing in the horizontal liner. When using packers, the packers isolate sections of the formations so that each section can be better treated for productivity. Between the packers is a frac port and in some cases a sliding sleeve or a casing that communicates with the formation. In order to direct a treatment fluid through a frac port and into the formation, a seat or valve may be placed close to a sliding sleeve or below a frac port. A ball may be dropped to land on the seat in order to direct fluid through the frac port and into the formation.

One method involves placing a series of ball seats below the frac ports covered by sliding sleeves with each seat size accepting a different ball size. Smaller diameter seats are at the bottom of the completion and the seat size increases for each zone going up the well. For each seat size, there is a ball size, so the smallest ball is dropped first to clear all the larger seats until it reaches the appropriate seat. In cases where many zones are being treated, as many as twenty zones or more, the seat diameters have to be very close. The balls that are dropped have less surface area to land on as the number of zones increase. With less seat surface to land on, the amount of pressure that can be applied on the ball, especially at elevated temperature, becomes less and less. Because the ball is so weak, with increasing pressure to frac the well, the ball often blows right through the seat. Furthermore, the small ball seats reduce the internal diameter (ID) of the production flow path, which creates other problems. The small ID prevents re-entry of other downhole devices, i.e., plugs, running and pulling tools, shifting tools for sliding sleeves, perforating gun size (smaller guns, less penetration), and of course production rates. In order to remove the seats, coiled tubing is used with a mill to mill out all the seats and any balls that remain in the well.

In another method of completion called “plug and perf”, the liner may be cemented in throughout the length of the horizontal section. Typically, composite plugs are run into the well on electric line and pumped out the horizontal section toward the toe until the composite plug is below the section of the zone to be fractured. Once at the desired location, a setting tool is actuated, and the composite plug sets inside of the liner. Perforating guns are sometimes run in the same electric line trip where once the composite plug is set, the guns and setting tool release away from the composite plug and are moved up to a location where the liner is perforated with the guns. Once perforated, the spent perforating gun and setting tool are returned to the surface. Frac fluid is then pumped into the well in order to frac the zone. After treatment, the next composite plug with setting tool and perforating guns is run to the next upper zone section and the process described above is repeated and obviously this becomes very time consuming. This process can be repeated many times, such as up to forty times. Once all zones have been fractured, a coiled tubing unit runs coiled tubing into the well with a motor and mill attached and all of the composite plugs are milled out. The composite plug mill debris is flowed back to the surface and the well is put on production.

BRIEF SUMMARY OF THE INVENTION

It is an object of some embodiments of the invention to provide apparatuses and methods for oil and gas wells to enhance the production of subterranean wells, either open hole, cased hole, or cemented in place and more particularly to improved multizone stimulation systems.

It is an object of some embodiments of the invention to utilize forces achieved from the frac pump for downward force and manipulation of a downhole packer tool to engage with and move the position of a sleeve port.

It is an object of some embodiments of the invention to provide fracture abilities with full internal diameter (ID) without perforating guns and without drilling out the internal diameter (ID) using coil tubing.

According to an exemplary embodiment of the invention there is disclosed a downhole tool being a packer run on wireline where the frac fluid force of the frac pump is used for downward manipulation. Advantages include that wireline is much cheaper than coil tubing, wells can be virtually endless in the horizontal leg, full internal diameter (ID) is achieved with no drill out and the avoidance of using explosives for perforating. Other exemplary benefits include enabling a high-pressure rating—for example, 10k psi—in some embodiments can easily achieve 15-20k psi. The tool may include a casing collar locator (CCL) for depth correlation. Other features in various embodiments include a spring running lengthwise within the tool and a bypass valve to provide upward force and overcome differential pressure. Either cups or elements may be used as seals in different embodiments. The ports can be open/closed after fracturing.

According to an exemplary embodiment, a downhole packer tool includes a center mandrel and a packer provided around the center mandrel. The tool further includes sleeve engaging members movable between extended and retracted positions to either engage with a port sleeve or allow the packer tool to pass by the sleeve without engagement. In a run mode of operation, the sleeve engaging members retract toward the center mandrel. In a set mode of operation, a hydraulic force of a fluid flowing through the wellbore in a downhole direction generates an outward force pushing the sleeve engaging members away from the center mandrel such that they engage with an adjacent port sleeve. Once engaged, hydraulic fluid pressure causes the packer to move the sleeve into an open position and expand the elements, creating a plug between previously fractured stages below and the wellbore above. While engaged with the sleeve, uphole force applied to the packer tool may also be used to move the sleeve into a closed position in a similar manner.

These and other advantages and embodiments of the present invention will no doubt become apparent to those of ordinary skill in the art after reading the following detailed description of preferred embodiments illustrated in the various figures and drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described in greater detail with reference to the accompanying drawings which represent preferred embodiments thereof:

FIG. 1 illustrates a downhole packer tool in a set mode of operation moving toward a downhole port according to an exemplary embodiment.

FIG. 2 illustrates the downhole packer tool of FIG. 1 in the set mode of operation after the profile blocks have engaged with the sleeve profile of the port.

FIG. 3 illustrates the downhole packer tool of FIG. 2 in the set mode of operation after pressure has built to a sufficiently high level in order to cause the packer tool to push the sleeve of the port into an open position thereby opening a plurality of port holes.

FIG. 4 illustrates the downhole packer tool in a run mode of operation being pulled in the uphole direction by wireline after the fractures of FIG. 3 are generated according to an exemplary embodiment.

FIG. 5 illustrates usage of the downhole packer tool to engage with a sleeve in preparation to open one of a plurality of ports preinstalled in a casing pipe according to an exemplary embodiment.

FIG. 6 illustrates a set of fractures created after the downhole packer tool has engaged with and opened the sleeve on the desired port as illustrated in FIG. 5.

FIG. 7 illustrates a cross section view of the packer tool illustrating a number of components therein.

FIG. 8 illustrates a cross sectional view of a port in the closed position according to an exemplary embodiment.

FIG. 9 illustrates a cross sectional view of a port in the open position according to an exemplary embodiment.

FIG. 10 illustrates a top view of a profile block with a center channel for increased support and slippage avoidance according to an exemplary embodiment.

FIG. 11 illustrates a side view of the profile block of FIG. 10.

FIG. 12 illustrates a bottom view of the profile block of FIG. 10.

FIG. 13 illustrates an end view of the profile block of FIG. 10.

FIG. 14 illustrates an end view of a cone including a plurality of cone extending elements for supporting the downhole side of profile blocks according to an exemplary embodiment.

FIG. 15 illustrates a side view of the cone of FIG. 14,

FIG. 16 illustrates a perspective view of the cone of FIG. 14.

FIG. 17 shows a side view of the cone extending element extending into part of the channel when the packer tool is operating in the run mode and the profile block is retracted.

FIG. 18 shows a side view of the situation after the first cone pushes against the side of the profile block while the profile block is engaged in the sleeve profile in the set mode of operation.

FIG. 19 illustrates a downhole port with integrated sleeve shock absorber in the closed position according to an exemplary embodiment.

FIG. 20 illustrates the downhole port of FIG. 19 after the sleeve has moved into the chamber according to an exemplary embodiment.

FIG. 21 illustrates a downhole port with a profile cavity provided on the inner surface of a shock absorber chamber wall according to an exemplary embodiment.

FIG. 22 illustrates the downhole port of FIG. 21 after the sleeve has moved into the chamber according to an exemplary embodiment.

DETAILED DESCRIPTION

FIG. 1 illustrates a downhole packer tool 100 in a set mode of operation moving toward a downhole port 102 according to an exemplary embodiment. The downhole packer tool 100 includes a center mandrel 104 that is hollow and includes a bypass window 106 on the uphole side and an adjoining bypass opening 108 on the downhole end. A drag assembly 110 provides frictional resistance as the tool moves along the casing 112. A plurality of profile blocks 114 extend though a body 116 of the tool 100 in the set mode as illustrated in FIG. 1. Packer elements 118 are included on the uphole side of the tool 100 along with a seal block 120 and a casing collar locator (CCL) 122. The tool 100 is suspended using wireline 124 that runs uphole to the surface. As illustrated by the arrows in FIG. 1, hydraulic forces exerted from fracture fluid 126 moving in the downhole direction push the packer tool 100 in the downhole direction.

The port 102 in FIG. 1 includes a cylindrical body 128 that has a moveable sleeve 130 inside. In this embodiment, the sleeve 130 is also cylindrical in shape and is adjacent and substantially encircles the full diameter of the inner surface of the port body 128. First and second O-rings 132, 134 ensure that fracture fluid 126 within the casing 112 cannot exit a port hole 136 in the body 128 of the port 102 while the sleeve 130 is in the closed position. The sleeve 130 includes a profile cavity 138 that encircles the inner surface of the sleeve 130 and substantially matches the shape of the profile blocks 114 extending from the body 116 of the packer tool 100. The profile blocks 114 of the packer tool 100 in the set mode of operation are biased to extend radially outward from the body 116 of the tool 100 in order to engage with the sleeve profile 138 when the tool 100 moves into position adjacent the sleeve 130. Shear pins 140 between the port body 128 and sleeve 130 hold the sleeve 130 in the closed position.

FIG. 2 illustrates the downhole packer tool 100 of FIG. 1 in the set mode of operation after the profile blocks 114 have engaged with the sleeve profile 138 of the port 102. Once the packer tool 100 moves into the position where the profile blocks 114 are directly adjacent the sleeve profile 138, the outward force of the profile blocks 114 causes the profile blocks 114 to enter into the cavity of the profile 138 and the tool 100 is held captive within the sleeve 130 of the port 102. At this point, the pressure of the fracture fluid 126 flowing in the downhole direction indicated by the arrows pushes against the seal block 120 on the now stationary packer tool 100 and moves the center mandrel 104 and sleeve block 120 forward until the seal block 120 is pushed up against the packer elements 118. The bypass window 106 is hidden under the packer elements 118 and the fluid 126 forces compressing the packer elements 118 cause the packer elements 118 to expand and seal off both the outer circumference of the packer elements 118 where they meet the casing 112 or other production flow path and also to seal off the bypass window 106 under the inner circumference of the packer elements 118 where they meet the center mandrel 104. Once the packer elements 118 have completely sealed off the production flow path, fluid 126 pressure continues to build on the uphole side of the packer tool 100 as generated by the frac fluid pumps at surface.

FIG. 3 illustrates the downhole packer tool 100 of FIG. 2 in the set mode of operation after pressure has built to a sufficiently high level in order to cause the packer tool 100 to push the sleeve 130 of the port 102 into an open position thereby opening the plurality of port holes 136. Once the port holes 136 are opened, high pressure fracture fluid 126 flows out these holes 136 and into the subterranean formation 142 where one or more fractures 144 are created.

FIG. 4 illustrates the downhole packer tool 100 in a run mode of operation being pulled in the uphole direction by wireline 124 after the fractures 144 of FIG. 3 are generated according to an exemplary embodiment. In the run mode of operation, the profile blocks 114 are retracted into the body 116 of the packer tool 100 and no longer engage with the profile 138 in the sleeve 130. At this point in time, the frac fluid 126 pumps are shut off and the tool 100 is pulled in the uphole direction by reeling in the wireline 124 at surface. Since there is no longer any significant hydraulic pressure in the downhole direction on the packer tool 100, the packer elements 118 are no longer compressed and the center mandrel 104 moves relative to the packer elements 118 in the uphole direction thereby exposing the bypass window 106. Fluid 126 in the casing 112 can thereby go around the outside of the packer tool 100 and can also pass through center mandrel 104 via the bypass window 106 and the bypass opening 108 on the downhole end of the mandrel 104. Pressure differential on the uphole and downhole sides of the packer tool 100 are thereby equalized.

FIG. 5 illustrates usage of the downhole packer tool 100 to engage with a sleeve 130 in preparation to open one of a plurality of ports 102 preinstalled in a casing pipe 112 according to an exemplary embodiment. In this embodiment, a well bore 500 is drilled downward and then outward in a horizontal section. For instance, the vertical section may go down 750 m and the horizontal section may kick horizontally another 1000 m. Casing 112 is installed such as 4.5″ casing having an internal diameter of 4″. The casing 112 includes a plurality of downhole ports 102 at periodic distances from one another at least in the horizontal section separated by a number of casing joints. For instance, two joints of casing 112 may separate each port 102. A special toe port 502 may be installed at the furthest most end of the casing 112. After the casing 112 is at the desired depth, it may be cemented between the open-hole and the casing or open-hole packers of some kind can partition the frac stages (or any combination thereof for different sections) and a completion phase begins to fracture the wellbore 500 and adjacent subterranean formation 142.

During the completion phase, tanks 504 of fracture fluid 126 are prepared at surface and the downhole packer tool 100 is installed on a wireline 124 ready for insertion into the wellbore 500. The toe port 502 is opened at this point and high-pressure fracture fluid 126 is pumped down the casing 112 in order to create a first set of fractures 144a at the toe 502 of the wellbore 500. This first set of fractures 144a is beneficial to allow fluid 126 to flow from surface down the casing 112 and into the formation 144 via the first set of fractures 144a.

The downhole packer tool 100 coupled to the surface via wireline 124 is lowered into the casing 112 and sent down the well 500. Gravity may be used to get the tool 100 to the heal 506 and then fracture fluid 126 pumped in the downhole direction is used to move the tool 100 further downhole along the horizontal section. While moving in the casing 112, the drag body 110 (see FIG. 1) grabs onto the 4″ internal diameter and provides some friction allowing manipulation of the middle portion of the tool 100 in order to change the packer tool 100 between the set and run modes of operation using different levels of physical force pulling up on the tool 100 via the wireline 124. While the tool 100 is being pumped out toward a first port 102a of interest, the wireline 124 is kept slack and the tool 100 stays in its current mode of operation. The initial mode is the run mode, which causes the profile blocks 114 to be retracted and therefore the tool 100 does not engage with any sleeve profiles 138 as it is pumped in the downhole direction.

Using the hydraulic force of fracture fluid 126 moving toward the toe port 502, the tool 100 is pumped out to be in the vicinity of a first target port 102a. The location of the tool may be determined from a combination of the amount of wireline 124 that has been spooled out along with casing collar location (CCL) 122 sensor signals received from the tool 100 via the wireline 124. Each time the tool 100 passes by a port 102, the CCL 122 sensor signals indicate this fact by detecting the increased metal thickness of the port 102. When reaching the target port 102a being the port adjacent the toe port 502, the fluid pumps are shut off and the operators pull the tool 100 uphole a small distance using the wireline 124. In this embodiment, the action of pulling up on the tool 100 using the wireline 124 combined with the resisting frictional forces of the drag body 110 against the inner sides of the casing 112 causes the packer tool 100 to switch into a set mode of operation. In the set mode of operation, the profile blocks 114 are biased to radially extend outwards for engaging with the sleeve profile 130.

Once in the set mode of operation, the fluid pumps are turned back on and the packer tool 100 is pushed downhole again by the hydraulic fluid 126 force toward the desired port 102a. Because the profile blocks 114 are now extended and pushing outwards against the casing 112, when the packer tool 100 reaches adjacent the sleeve 130 of the target port 102a, the profile blocks 114 enter and engage with the sleeve profile 138 and the packer tool 100 is held captive against the sleeve 130. At this point, the packer tool 100 stops moving downhole and the operators at surface no longer observe wireline 124 spooling out. In response to observing this condition, the fluid 126 rate and pressure may be increased by the surface operators to any desired level to apply more downhole pressure on the packer tool 100. As pressure increases, the packer elements 118 compress causing them to bulge outwards and seal off the casing 122 and fluid 126 flow. As previously mentioned, the seal block 120 also moves the center mandrel 104 forward and blocks off the bypass window 106. The production flow path is thereby sealed by the packer tool 100. Since there is no longer anywhere for the fracture fluid 126 to go, pressure builds and hydraulic forces in the downhole direction are transferred from the packer tool 100 via the profile blocks 114 to the sleeve 130. The sleeve 130 includes shear pins 140 that snap at a predetermined force thereby allowing the sleeve 130 to move from the closed position to the open position as pushed by the packer tool 100.

FIG. 6 illustrates a set of fractures 144b created after the downhole packer tool 100 has engaged with and opened the sleeve 130 on the desired port 102a as illustrated in FIG. 5. After the sleeve 130 has been pushed open by the packer 100 acting under force of the hydraulic fluid 126, the fluid 126 can exit the casing 112 via the newly opened port hole 136 and thereby fracture 144b the adjacent formation 142.

FIG. 7 illustrates a cross section view of the packer tool 100 illustrating a number of components therein according to an exemplary embodiment. In this view, the tool body 116 has been removed to better illustrate the internal operations. In addition to the components illustrated earlier in FIG. 1, the packer tool 100 of this embodiment further includes a first cone 700 and a second cone 702 for pushing up on corresponding angled edges 704 of the profile blocks 114. A J-track 706 is provided to allow the surface operators to switch the tool's 100 mode of operation between set mode and run mode by pulling up on the tool 100 via the wireline 124. A differential spring 708 is included on the center mandrel 104 and acts to push up on the mandrel 104 for the purposes of overcoming differential pressure, and thereby downward force, from above which acts to keep the packer tool 100 in place, thereby aiding the wireline 124 when pulling the tool 100 off stage after a frac. In this embodiment, the drag body 110, the seal block 120, and the downhole side 702a of the second cone 702 are fixed in position around the center mandrel 104; however, the uphole side 702b of the second cone 702 along with the first cone 700 and packer elements 118 are movable along the mandrel 104 as hydraulic and wireline 124 forces change. In particular, the first cone 700 and the second cone 702 may move closer together when hydraulic fluid 126 forces are applied against the packer elements 118 in the downhole D direction. The second cone 702 will tend to resist the D direction as a result of the friction caused from the drag body 110 against the casing 112. The motion of the cones 700, 702 coming together applies pressure to the angled inner sides 704 of the profile blocks 114 therefore pushing the profile blocks 114 radially outward in the R direction.

The center mandrel 104 in this embodiment also includes a mandrel sleeve 710 upon which the seal block 120 along with the bypass window 106 are mounted. As the seal block 120 is pushed in the downhole direction D, the mandrel sleeve 710 moves in the downhole direction D as well thereby moving the bypass window 106 under the packer elements 118. This movement of the mandrel sleeve 710 in the downhole direction D is resisted by the differential spring 708 which tends to push the mandrel sleeve 710 in the uphole direction opposite D by the forces of the drag assembly 110.

The mode switch is actuated in some embodiments by a J-track 706 adjacent the profile blocks 114. The J-track 706 is a known mechanism used in the setting and unsetting of downhole tools and equipment such as packers. The downhole packer tool 100 of this embodiment is switched modes by an upward and then downward movement. The J-slot profile 706 creates the track for an actuating cam 712 or pin 714 that alternatingly moves the tool 100 into 1) a set mode configuration where the first cone 700 and the second cone 702 are enabled to come closer together, and 2) a run mode configuration where the first cone 700 and the second cone 702 are prevented from coming close together. In the set mode, the cones 700, 702 can come closer together therefore pushing the profile blocks 114 outward in the R direction. In the run mode, the cones 700, 702 are prevented from coming together and therefore do not push the profile blocks 114 outward in the R direction; instead, springs 1700 (see FIGS. 17 and 18) keep the profile blocks 114 retracted in the run mode of operation. As J-tracks 706 are well understood in the art, further description of the J-track 706 for switching between set and run modes is omitted herein.

The differential spring 708 helps overcome the differential pressure that may be apparent between the downhole side of the packer elements 118 and the uphole side of the packer elements 118 even after the fluid 126 pumps are shut off After the pumps are shut off, there is no longer any downhole force applied against the seal block 120 and the differential spring 708 therefore pushes the center mandrel sleeve 710 in the uphole direction. The bypass window 106 is thereby exposed and pressure differences on either side of the packer elements 118 is equalized via fluid 126 flowing between the bypass window 106 and bypass opening 108. Without a pressure difference, the packer elements 118 decompress (i.e., unseal from the sleeve 130 inner surface) and the packer tool 100 can be removed from the port 102 by surface operators activating motors to pull up on the wireline 124.

FIG. 8 illustrates a cross sectional view of a port 102 in the closed position according to an exemplary embodiment. As illustrated, a number of port holes 136 are blocked by a sleeve 130. The sleeve 130 includes a profile 138 for engaging with the profile blocks 114 of the tool 100. Rubber O-rings 132, 134 are located on either side of the port holes 136 and prevent fluid 126 from passing through a gap 800 between the cylindrical body 128 and the sleeve 130 in order to reach the port holes 136 when the sleeve 130 is in the closed position.

FIG. 9 illustrates a cross sectional view of a port 102 in the open position according to an exemplary embodiment. After being pushed open by the downhole packer tool 100, the sleeve 130 no longer covers the port holes 136. Fluid 126 may therefore freely exit the port 102 interior via the port holes 136 for fracturing or otherwise interacting with surfaces such as cement and/or formation 142 outside the port holes 136.

FIGS. 10 to 13 illustrate different views of a profile block 114 with a center channel 1000 for increased support and slippage avoidance according to an exemplary embodiment. FIG. 10 illustrates a top view, FIG. 11 illustrates a side view, FIG. 12 illustrates a bottom view, and FIG. 13 illustrates an end view. In this embodiment, each profile block 114 includes a center channel 100 that runs lengthwise from an uphole end 1002 toward a downhole end 1004 of the profile block 114. The center channel 1000 does not fully run to the downhole end 1004 and instead ends near the end 1004 with an angled surface 1006 similar in angle to the angled edge 1008 against which the profile block 114 is pushed by the first cone 700.

FIGS. 14 to 16 illustrates different view of the first cone 700 including a plurality of cone extending elements 1400 for supporting the downhole side 1004 of profile blocks 114 according to an exemplary embodiment. FIG. 14 illustrates an end view showing a base 1402 of the cone 700, a top 1404 of the cone 700, and a plurality of cone extending members 1400. FIG. 15 illustrates a side view of the cone of FIG. 14, and FIG. 15 illustrates a perspective view.

FIG. 17 and FIG. 18 illustrate structure and operation of the first cone 700 having an integrated cone extending element 1400 protruding from the first cone 700 and extending into the center channel 1000 on the profile block 114. In particular, FIG. 17 shows the cone extending element 1400 extending into part of the channel 1000 when the packer tool 100 is operating in the run mode and the profile block 114 is retracted. In the run mode of operation, the distance between the first cone 700 and the second cone 702 is such that the profile block 114 is not pushed radially outwards. Instead, a spring 1700 between the profile block 114 and the tool body 116 pushes the profile block 114 down into the body 116 in order to retract the profile block 114.

FIG. 18 shows the situation after the first cone 700 pushes against the side 704 of the profile block 114 while the profile block 114 is engaged in the sleeve profile 138 in the set mode of operation. As pressure builds, the side 1800 of the first cone 700 will naturally push against the uphole side 704 of the profile block 114. Because the angles of these sides 704, 1800 match at forty-five degrees in this embodiment, the uphole side 704 of the profile block 114 will be pushed radially outward in the R direction. Additionally, because the cone extending member 1400 extends down the channel 1000 and meets at a forty-five degree angle with the downhole end 1004 of the channel, the downhole-directed forces exerted by the cone extending element 1400 push the downhole side 1004 of the profile block 114 radially outward in the R direction. Thus, both the downhole side 1004 and the uphole side 1002 of the profile block 114 are pushed outward in the R direction and slippage of the profile block 114 out of the sleeve profile 138 is prevented.

In some embodiments, the cone extending member 1400 is omitted; however, without the cone extending member 1400, the downhole side 1004 of the profile block 114 may have little outward force in the R direction because the second cone 702 is only pushed in the R direction by forces resulting from the drag assembly 110, which typically has very little friction and therefore little force compared to the forces exerted against the profile block 114 by the first cone 700 when the profile block 114 is engaged in the sleeve profile 138.

FIG. 19 and FIG. 20 illustrate an embodiment of a downhole port 102 including a sleeve shock absorber 1900. FIG. 19 illustrates the downhole port 102 in the closed position according to this embodiment. As illustrated, the port 102 includes a sleeve chamber 1902 formed by a chamber wall 1904 that forms an enclosed chamber area 1902 between the sleeve wall 1904 and the outer body 128 of the port 102. Rubber O-ring seals 1906, 1908 are provided to prevent fluid 126 from passing through a gap 1910 between the chamber wall 1904 and the sleeve 130 in order to reach the inner area 1912 of the cylindrical body 128. A first O-ring 1906 is adjacent an outside surface of the sleeve 130 and a second O-ring 1908 is adjacent an inside surface of the sleeve 130. One or more vent holes 1914 provide a path for fluid 126 to travel between the chamber 1902 and the inner area 1912 of the cylindrical port body 128.

FIG. 20 illustrates the downhole port 102 of FIG. 19 after the sleeve 130 has moved into the chamber 1902 according to an exemplary embodiment. As illustrated, when the sleeve 130 moves into the chamber 1902, it displaces fluid 126 which must therefore exit the chamber 1902 via the vent hole(s) 1914. However, because the vent hole 1914 is of limited size relative to the amount of fluid 126 held in the chamber 1902, it takes time for the movement of the sleeve 130 to squeeze the chamber fluid 126 out the vent hole 1914 to allow the sleeve 130 to enter the chamber 1902. In this way, movement of the sleeve 130 into the chamber 1902 is slowed and physical shock to the sleeve 130, port 102 and tool 100 in general is reduced.

FIG. 21 and FIG. 22 illustrate an embodiment of a downhole port 102 including a sleeve shock absorber 1900 similar to described above; however, now the port 102 includes a profile cavity 2100 on the inner surface of the chamber wall 1904. In this embodiment, the sleeve profile 138 is removed from the sleeve 130 and instead the chamber wall 1904 includes a profile 2100 for holding the downhole tool 100 captive when the tool 100 is in the set mode of operation.

FIG. 21 illustrates the downhole port 102 in the closed position according to this embodiment and FIG. 22 shows the port 102 with the sleeve 130 is moved into the open position. As illustrated, the profile 2100 is provided on the chamber wall 1904 and thus the downhole packer tool 100 will remain stationary when engaged in the profile 2100 both when the sleeve 130 is open and closed. Unlike the above embodiments, the tool 100 does not move physically in order to push open the port sleeve 130 in this embodiment. Instead, the tool 100 mounts securely adjacent the chamber wall 1904 and seals off the production flow path. As fluid 126 pressure builds, the sleeve 130 itself experiences hydraulic force pushing the sleeve 130 in the downhole direction and into the sleeve cavity 1902. Once the sleeve 130 has moved into the chamber, the port holes 136 are opened. The various O-ring seals 1906, 1908, 132, 134 prevent fluid from flowing around the sleeve 130 and out the vent hole(s) 1914.

Although the invention has been described in connection with preferred embodiments, it should be understood that various modifications, additions and alterations may be made to the invention by one skilled in the art without departing from the spirit and scope of the invention. For example, although the above description has focused on a downhole packer tool 100 with profile blocks 114 that engage with a corresponding profile 138 in a port sleeve 130, other types of sleeve engaging members instead of or in addition to profile blocks 114 can be used in a similar manner. For instance, in other embodiments, the downhole packer tool 100 may instead include slips that are either extended in a set mode or retracted in a run mode. The slips may engage with the inner surface of a slidable sleeve 130 of a port with or without any corresponding profile 138. In this way, the same feature of engaging the packer tool 100 to a sleeve 130 and then pushing the sleeve 130 open via hydraulic forces applied against the packer 100 can advantageously be used in other embodiments without the profile 138 and profile blocks 114. Likewise, the slips may engage with a chamber wall 1904 without the profile 2100. Thus, the hydraulic pressure caused by the packer tool 100 sealing off production flow can be used in other embodiments with the profile 2100 and profile blocks 114. Different modes of locating the packer tool 100 to the correct position without profile blocks 114 and corresponding profile 138, 2100 to help guide the position include using the sensor signals from the CCL 122. However, that said, utilizing the profile blocks 114 to engage and be held captive within a sleeve profile 130 or a chamber wall profile 2100 as described above has an advantage that the downhole packer tool 100 is ensured to be positioned at a safe distance from the port holes 136. This is particularly beneficial when sand passes by the port holes 126 under extreme pressures and speed during fracturing operations. Damage to the packer 100 is prevented by positioning the packer tool 100 a safe distance away from the port holes 136.

In another example modification, instead of using one or more packer elements 118 as described above to seal off the product flow line, the packer tool 100 in other embodiments may use cups. The principle of operation remains the same and the cups may extend outward and seal off the flow after the packer tool 100 is held captive adjacent the sleeve 130 and/or chamber wall 1904.

In yet another example modification, the wireline 124 described herein to pull the packer tool 100 up-hole may be replaced in other embodiments with slickline. Slickline may prevent the use of the CCL 122 sensor because the signals may have no wired path to surface; however, costs may be beneficially reduced in some applications by the omission of both the CCL 122 sensors in the packer tool 100 and from using slickline instead of wireline 124 to retract the tool back to surface and switch modes of operation. Of course, although both slickline and wireline 124 are beneficial because they are cheaper than coiled tubing, in other embodiments, the packer tool 100 may also be controlled from surface using coiled tubing.

In yet other example embodiments, the open ports 102 after fracturing is complete may be closed by the downhole packer tool 100. For instance, after the frac fluid 126 pumps are stopped, the surface operators may pull upward on the wireline 124 in order to remove the packer tool 100 from the sleeve 130. In some embodiments, springs may be included in the port sleeves 130 that are biased to keep the port sleeve 130 closed absent packer tool 100 applied forces. As such, upon removal of the packer tool 100 from the sleeve 130, the sleeves 130 will automatically close. In yet other embodiments, the action of removing the packer 100 from the sleeve 130 may close the port sleeve 130 such as by sliding the sleeve 130 to the closed position before the profile blocks 114 disengage from the sleeve profile 138.

According to an exemplary embodiment, a downhole packer tool 100 used in a wellbore 500 includes a center mandrel 104 and a packer 118 provided around the center mandrel 104. The tool 100 further includes sleeve engaging members 114 movable between extended and retracted positions to either engage with a port sleeve 130 or allow the packer tool 100 to pass by the sleeve 130 without engagement. In a run mode of operation, an inward force retracts the sleeve engaging members 114 toward the center mandrel 104. In a set mode of operation, a hydraulic force of a fluid 126 flowing through the wellbore 500 in a downhole direction generates an outward force that pushes the sleeve engaging members 114 away from the center mandrel 104 such that they engage with an adjacent port sleeve 130. Once engaged, hydraulic fluid 126 pressure causes the packer tool 100 to move the sleeve 130 into an open position. While engaged with the sleeve 130, uphole force applied to the packer tool 100 may also be used to move the sleeve 130 into a closed position in a similar manner.

The steps of utilizing the downhole packer tool 100 to engage with and open sleeves 130 on ports 102 as described and illustrated herein are not restricted to the exact order described, and, in other embodiments, described steps may be omitted or other intermediate steps added. Functions of single modules may be separated into multiple units, or the functions of multiple modules may be combined into a single unit. All combinations and permutations of the above described features and embodiments may be utilized in conjunction with the invention.

Claims

1. A downhole packer tool for use in a wellbore, the downhole packer tool comprising: a center mandrel;a packer provided around the center mandrel;a first cone provided around the center mandrel;a body provided around an outward-facing surface of the first cone and forming an inner area between the outward-facing surface of the first cone and an inward-facing surface of the body;a profile block within the inner area, the profile block being extendable and retractable through a hole in the body; anda spring between the profile block and the inward-facing surface of the body;wherein, in a run mode of operation, an inward force exerted by the spring retracts the profile block toward the center mandrel; andin a set mode of operation, a hydraulic force of a fluid flowing through the wellbore in a downhole direction pushes the first cone in the downhole direction relative to the profile block and an outward force exerted by the outward-facing surface of the first cone against the profile block overcomes the inward force of the spring and pushes the profile block away from the center mandrel such that the profile block extends radially outward through the hole in the body further than in the run mode of operation.

2. The downhole packer tool of claim 1, further comprising: a drag assembly provided around the center mandrel; anda second cone provided around the center mandrel and adjacent the drag assembly;wherein at least one of the first cone and the second cone are movable along the center mandrel;the body is provided around outward-facing surfaces of both the first cone and the second cone thereby forming the inner area therebetween;in the set mode of operation, the hydraulic force of the fluid flowing through the wellbore in the downhole direction pushes the first cone and the second cone together and outward forces exerted by outward-facing surfaces of the first cone and the second cone against the profile block overcomes the inward force of the spring and pushes the profile block away from the center mandrel.

3. The downhole packer tool of claim 2, further comprising a differential spring intermediate between the first cone and second cone, the differential spring pushing the first cone and the second cone apart until overcome by the hydraulic force of the fluid flowing in the wellbore in the set mode of operation pushing the first cone and the second cone together.

4. The downhole packer tool of claim 1, further comprising: a bypass window on the center mandrel;a seal block on the center mandrel on an uphole side of the bypass window; anda bypass valve on a downhole end of the center mandrel;wherein the center mandrel is hollow thereby allowing the fluid flowing in the wellbore to enter the center mandrel via the bypass window and to exit the center mandrel via the bypass valve.

5. The downhole packer tool of claim 4, wherein: the packer is movable along the center mandrel;the seal block is mounted to a fixed position on the center mandrel; andthe bypass window is positioned on the center mandrel such that, in the set mode of operation, the bypass window is sealed closed under the packer as a result of hydraulic pressure on the seal block in the downhole direction moving the center mandrel in the downhole direction relative to the packer.

6. The downhole packer tool of claim 1, wherein the profile block includes an angled edge that abuts against and substantially matches an angle of an outside-facing surface of the first cone.

7. The downhole packer tool of claim 6, further comprising: a channel extending from an uphole side of the profile block toward but not fully reaching a downhole side of the profile block; anda cone extending element protruding from the first cone for extending through the channel;wherein the channel and the cone extending element at their downhole sides have corresponding angles that substantially match the angle of the outside-facing surface of the first cone; andin the set mode of operation, outward forces exerted by the downhole side of the cone extending element pushes up the downhole side of the profile block thereby further pushing the profile block away from the center mandrel.

8. The downhole packer tool of claim 1, further comprising a J-track for switching modes between the set mode of operation and the run mode of operation.

9. The downhole packer tool of claim 1, further comprising a casing collar locator (CCL) sensor.

10. The downhole packer tool of claim 1, further comprising a line attachment for attaching an uphole end of the downhole packer tool to a wireline.

11. The downhole packer tool of claim 1, further comprising a line attachment for attaching an uphole end of the downhole packer tool to a slickline.

12. A downhole port comprising: a cylindrical body;a sleeve coupled to the cylindrical body and slidable from a closed position to an open position;a port hole on the cylindrical body; anda profile on an inner surface of the sleeve;wherein, in the closed position, the sleeve blocks the port hole and prevents a fluid within the cylindrical body passing through the port hole; andin the open position, the sleeve is moved such that the port hole is open and the fluid within the cylindrical body can pass through the port hole to exit the cylindrical body.

13. The downhole port of claim 12, further comprising one or more cylindrical seals that prevent the fluid from passing through a gap between the cylindrical body and the sleeve in order to reach the port hole on the cylindrical body when the sleeve is in the closed position.

14. The downhole port of claim 13, wherein the one or more cylindrical seals include at least two O-rings, a first O-ring on an uphole side of the port hole and a second O-ring on a downhole side of the port hole.

15. The downhole port of claim 12, further comprising: a chamber into which the sleeve enters when moving to the open position; anda vent hole from the chamber to an inner area of the cylindrical body;wherein, the sleeve entering the chamber pushes the fluid in the chamber through the vent hole.

16. The downhole port of claim 15, further comprising one or more cylindrical seals that prevent the fluid from passing through a gap between a chamber wall and the sleeve in order to reach the inner area of the cylindrical body when the sleeve moving from the closed position to the open position.

17. The downhole port of claim 16, wherein the one or more cylindrical seals include at least two O-rings, a first O-ring adjacent an outside surface of the sleeve and a second O-ring adjacent an inside surface of the sleeve.

18. A method of fracturing an oil and gas well in a wellbore, the method comprising: pumping fracture fluid in a downhole direction into the wellbore at low pressure to move a downhole packer tool down the wellbore, the downhole packer tool being configured in a run mode of operation while being moved in the downhole direction, a plurality of profile blocks on the downhole packer tool being retracted in the run mode operation;determining when the downhole packer tool is adjacent a first sleeve connected in a casing, the first sleeve being in a closed configuration prevents fracture fluid from exiting the casing through a port covered by the first sleeve;stopping one or more fracture fluid pumps and pulling up on a wireline coupled to the downhole packer tool in order to switch the downhole packer tool to a set mode of operation and ensure the downhole packer tool is above the first sleeve in the wellbore in response to determining the downhole packer tool is adjacent the first sleeve;pumping the fracture fluid down the casing at low pressure in order to move the downhole packer tool in the set configuration in the downhole direction of the wellbore until the profile blocks of the downhole packer tool engage with a first profile on the first sleeve;pumping the fracture fluid down the casing at high pressure in order to cause a packer of the downhole packer tool to seal against the first sleeve, to cause hydraulic forces against the downhole packer tool push the first sleeve into an open configuration thereby allowing the fracture fluid to exit the casing via a plurality of ports of the first sleeve, and to create one or more fractures extending from the first sleeve;stopping the fracture fluid pumps and pulling up on the wireline to remove the downhole packer tool from the first sleeve and to move the downhole packer tool in an uphole direction.

19. The method of claim 18, wherein, after stopping the fracture fluid pumps and pulling up on the wireline to remove the downhole packer tool from the first sleeve and to move the downhole packer tool in the uphole direction, the method further comprising: continuing to pull up on the wireline until determining that the downhole packer tool is adjacent a second sleeve;ensuring the downhole packer tool is above the second sleeve and in the set mode of operation;pumping the fracture fluid down the casing at low pressure in order to move the downhole packer tool in the set configuration in the downhole direction of the wellbore until the profile blocks of the downhole packer tool engage with a second profile on the second sleeve;pumping the fracture fluid down the casing at high pressure in order to cause the packer of the downhole packer tool to seal against the second sleeve, to cause hydraulic forces against the downhole packer tool to push the second sleeve into the open configuration thereby allowing the fracture fluid to exit a plurality of ports of the second sleeve, and to create one or more fractures extending from the second sleeve;stopping the fracture fluid pumps and pulling up on the wireline to remove the downhole packer tool from the second sleeve and to move the downhole packer tool in the uphole direction.

20. The method of claim 18, further comprising: connecting a plurality of sleeves at predetermined distances in the casing of the wellbore, each sleeve installed in the closed configuration, the sleeves connected in a series arrangement such that a first member of the series is at a downhole end of the wellbore and a last member of the series is at an uphole end of the wellbore;opening a toe port in the casing;pumping fracture fluid down the casing at high pressure in order to generate a first fracture from the toe port thereby allowing the fracture fluid to flow in the wellbore in the downhole direction; andutilizing the downhole packer tool to open each sleeve and generating fractures from each sleeve start from the first member of the series at the downhole end and finishing at the last member of the series at the uphole end of the wellbore.