US20140151052A1

US20140151052A1 - Kobe sub with inflow control, wellbore tubing string and method

Info

Publication number: US20140151052A1
Application number: US13/883,218
Authority: US
Inventors: Daniel Jon Themig; Robert Joe Coon
Original assignee: Packers Plus Energy Services Inc
Current assignee: Packers Plus Energy Services Inc
Priority date: 2011-06-20
Filing date: 2012-06-20
Publication date: 2014-06-05
Also published as: EP2721247A4; CA2837771A1; EP2721247A1; WO2012174662A1; BR112013032427A2

Abstract

A kobe sub includes a kobe installed in a port of the sub, the kobe includes a cap portion accessible in the inner bore, a base mounted in the port and connected to the cap portion, a channel extending through the base and closed by the cap portion; and an inflow controller positioned to control fluid flowing through the channel toward the inner bore when the cap portion is opened; and a port opening tool for opening the cap portion. The kobe may be employed with a frac port.

Description

FIELD

The invention is directed to a wellbore apparatus and method and, in particular a kobe sub, wellbore tubing string and method.

BACKGROUND

In wellbore operations, tubing strings are used having walls with one or more ports extending therethrough. The ports permit fluid access between the tubing string inner diameter and the tubing string's outer surface, which is open to the wellbore.
A kobe, also called a break-off plug or a kobe plug, is a closure that can be mounted at its base over a port with a cap portion extending from the base. A channel extends through the base into the cap, but is closed off at the cap. The cap portion protrudes from the port and is openable to open the port to fluid flow through the channel. A kobe is installed in a port through the wall of a tubular housing, together called a kobe sub, that can be installed into a wellbore tubing string. The cap portion of the kobe often protrudes into the inner bore of the tubing string.
Generally, the kobe is opened by running a tool through the inner bore of the string to break off the cap portion. The tool may be a drop bar, a cutter tool, etc.
Tubing strings may handle fluid flows into and out of the wellbore. For example, an oil or gas well relies on inflow of petroleum products to the tubing string and toward surface. It may be advantageous in certain circumstances to control the inflow of produced fluids. For example, it may be advantageous to screen the produced fluids before they enter the tubing string. In addition or alternately, the produced fluids may require flow rate control, as by use of chokes including devices called inflow control devices (ICD).

SUMMARY

In accordance with a broad aspect of the present invention, there is provided a kobe sub comprising: a tubular body connectable into a wellbore tubing string, the tubular body including a wall including an outer surface and an inner surface defining an inner bore and a port through the wall; a kobe installed in the port with a cap portion accessible in the inner bore, a base mounted in the port and connected to the cap portion, a channel extending through the base and closed by the cap portion; and an inflow controller positioned to control fluid flowing through the channel toward the inner bore when the cap portion is opened.
In accordance with another broad aspect of the present invention, there is a provided a method for forming a fluid channel through a tubing string wall, the method comprising: installing a tubing string in a wellbore, the tubing string including a tubular wall including an outer surface and an inner surface defining an open inner bore and a port through the wall; a kobe installed in the port with a cap portion accessible in the inner bore, a base mounted in the port and connected to the cap portion, a channel extending through the base and closed by the cap portion; and an inflow controller positioned to control fluid flowing through the channel toward the inner bore when the cap portion is opened; manipulating a port opening tool in the inner bore to open the cap portion and to allow fluid flow through the inflow controller and the channel into the inner bore.
In accordance with another broad aspect of the present invention, there is a provided a tubing string system for installation in a wellbore comprising: a tubular body including a tubular wall with an outer surface and an inner surface defining an inner bore and a port through the tubular wall; a kobe installed in the port with a cap portion accessible in the inner bore, a base mounted in the port and connected to the cap portion, a channel extending through the base and closed by the cap portion; and an inflow controller positioned to control fluid flowing through the channel toward the inner bore when the cap portion is opened; and a port opening tool for opening the cap portion.
In accordance with another broad aspect, there is provided a method for fluid treatment of a borehole, the method comprising: running a tubing string into a wellbore to a desired position for treating the wellbore; opening a frac port by application of a force to a closure for the frac port; injecting stimulating fluids through the frac port; closing the frac port; opening a fluid inflow control port by opening an inner cap over the fluid inflow control port; and permitting fluid to pass from the wellbore into the tool through the fluid inflow control port.
It is to be understood that other aspects of the present invention will become readily apparent to those skilled in the art from the following detailed description, wherein various embodiments of the invention are shown and described by way of illustration. As will be realized, the invention is capable for other and different embodiments and its several details are capable of modification in various other respects, all without departing from the spirit and scope of the present invention. Accordingly the drawings and detailed description are to be regarded as illustrative in nature and not as restrictive.

BRIEF DESCRIPTION OF THE DRAWINGS

A further, detailed, description of the invention, briefly described above, will follow by reference to the following drawings of specific embodiments of the invention. These drawings depict only typical embodiments of the invention and are therefore not to be considered limiting of its scope. In the drawings:

FIG. 1 is a sectional view along the long axis of kobe sub;

FIG. 2 is a sectional view along the kobe sub of FIG. 1 undergoing a port opening operation;

FIG. 3 is a perspective view of a fluid control port insert useful in the present invention;

FIG. 4 is a sectional view along the kobe sub of FIG. 1 undergoing another type of port opening operation;

FIG. 5 a is a sectional view along a kobe sub undergoing another type of port opening operation;

FIGS. 5 b to 5 d are a series of drawings showing a kobe opening operation;

FIG. 6 is a sectional view along the kobe sub of FIG. 5 with its ports open;

FIG. 7 is a sectional view along the long axis of another kobe sub;

FIG. 8 is a sectional view along the kobe sub of FIG. 7 undergoing a port opening operation;

FIG. 9 is a sectional view along the kobe sub of FIG. 7 with its ports open;

FIG. 10 is a sectional view along the long axis of a frac tool in the form of a tubing string sub containing a sleeve in a closed port position;

FIG. 11 is a sectional view along the sub of FIG. 10 with the sleeve in a position allowing fluid flow through injection ports;

FIG. 12 is a sectional view along the sub of FIG. 10 allowing fluid flow through fluid inflow control ports; and

FIG. 13 is a sectional view along a tubing string in a wellbore.

DETAILED DESCRIPTION

The description that follows, and the embodiments described therein, is provided by way of illustration of an example, or examples, of particular embodiments of the principles of various aspects of the present invention. These examples are provided for the purposes of explanation, and not of limitation, of those principles and of the invention in its various aspects. The drawings are not necessarily to scale and in some instances proportions may have been exaggerated in order more clearly to depict certain features. Throughout the drawings, from time to time, the same number is used to reference similar, but not necessarily identical, parts.
A method and apparatus has been invented which provides for flow control of produced fluids. The apparatus and methods of the present invention can be used in various borehole conditions including open holes, cased holes, vertical holes, horizontal holes, straight holes or deviated holes.
FIG. 1 illustrates a kobe sub 10 that includes kobes 12 as closures for ports 16 through the sub wall.
Kobe sub 10 may have a tubular form and include an upper end 10 a, a lower end 10 b and a wall 18 defining the subs inner bore ID and its outer surface 20. At least one fluid outlet port 16 extends through the wall to provide fluid communication between inner bore ID and outer surface 20. In wellbore operations, kobe sub 10 may be installed in a wellbore and, as such, outer surface 20 becomes open to an annulus in communication with the wellbore wall.
In some embodiments, there may be a plurality of fluid ports 16 through the wall of the sub. As shown for example, ports 16 may extend through the wall and may be spaced circumferentially and/or axially along the sub wall.
Ports 16 may each be closed by kobes to permit isolated control of the fluid conditions in inner bore ID and may be selectively openable, when desired, to permit fluid access between the inner bore and the outer surface.
Each kobe includes a cap portion 12 a, a base 12 b attached to the cap portion, and a channel 12 c that extends through the base. The kobe can be mounted at its base 12 b in a port with its cap portion 12 a protruding beyond the surrounding wall surface defining inner diameter ID. The base can be sealed to the port walls, such that channel 12 c creates the flow path through the port. Cap portion 12 a, however, while it is in place on the base, seals channel 12 c against fluid flow therethrough. Cap portion 12 a, therefore, must be opened to open the port to fluid flow. The cap portion can be opened by removing, shearing, breaking off, compromising, breaching, breaking open, pushing through the wall, etc, which may be collective referred to herein as “opened”. Sometimes, the kobe includes a weakened area 12 d between cap portion 12 a and base 12 b that facilitates opening removal by separation of the cap portion from the base, when force is applied to cap portion 12 a.
Kobe sub 10 may be connected into a wellbore string for installation into a well. For example, its ends 10 a, 10 b may be formed for connection in line with other tubulars. For example, its ends may be threaded and formed as pins or boxes for typical threaded connection to other tubulars.
Kobe sub 10 illustrated in FIG. 1 has ports 16 particularly suited to controlling fluid flows therethrough. For example, each port 16 has a fluid inflow controller 24 installed therein. Fluid inflow controller 24 may be selected to control any of various features of the fluid passing therethrough. For example, the fluid inflow controller may be a screen, as shown, for filtering out oversize solids from the fluid, and/or may a choke for controlling the pressure drop and/or flow rate of the fluid passing through port 16. One type of choke is commonly known as an inflow control device (ICD). ICDs use various mechanisms to control velocity, flow rate and pressure drop such as labyrinths, surface roughening, passage arrangements, nozzles, gates, etc.
For each port, when cap portion 12 a is in place, flow is prevented through channel 12 c and therefore controller 24 is inactive. However, when cap portion 12 a is opened, the fluid inflow controller acts on the fluids passing inwardly through the port through channel 12 c.
FIG. 1 shows sub 10 with all ports 16 closed by their kobes. This is the run in state of the tool. In this condition, controllers 24, in this embodiment screen inserts, are installed with kobes 12 sealing them from the ID of the tubing. In this state, the tubing at the location of sub 10 has a full pressure rating, substantially equal to a section of standard tubing without ports. In this condition, an operator can circulate fluid through the inner diameter ID of sub 10, which may be needed for example to run the tubing string in the hole. The sub is also able to hold higher pressures, such that the operator may pressure up the string at the sub to use tubing pressure to set packers or treat the formation through the string.
When a controlled, for example screened, return flow is desired, the kobes can be opened to permit flow through the ports. Various methods can be employed to open the ports to flow therethrough. For example, the cap portions can be opened by: (i) milling through the inner diameter, (ii) abutment by a string conveyed tool, or (iii) abutment by an unconnected tool, such as a gravity or fluid conveyed tool.
For example, FIG. 2 shows sub 10 after it has been connected into a tubing string and installed in a wellbore, as indicated by wall 26. After the tubing string is installed and before or after other wellbore operations of interest are conducted, the operator may wish to open the ports by opening cap portions 12 a. In this illustrated embodiment, a shifting tool 50 on a string 52, such as for example, slickline, coiled tubing or threaded pipe, is run to the bottom of the well, activated and pulled (arrow P) back toward the surface. Tool activation releases the tool's keys 54 to expand so they abut against and shear off the kobe cap portions 12 a as the keys pass ports 16. Shearing cap portions 12 a′, which are accessible in the ID of the tubing string, from their bases 12 b, opens channels 12 c for fluid communication between the ID and an annulus 56 between wall 26 and outer surface 20 of the tubing string. When opened, for example, produced fluids, arrows F, may flow through screen 24 and through channel 12 c into the inner diameter ID of the tubing string and be produced to surface.
Of course this process could also be done running from the top of the well to the bottom, but typically it is easier to pull with force then to push with force. The sheared off cap portions 12 a′ of the kobes are shown released into the ID of the tubing string and may be produced to the surface when the well goes on production. However, if desired, the cap portions can be stored in the tubing string or captured such that they do not become freed in the inner diameter, as described in applicant's corresponding PCT application no. WO 2012/065259. Also or alternatively in some embodiments, there they may be a concern of a cap portion being inadvertently opened by abutment by an actuator, a treatment string or tool head, as they are passed thereby. In such an embodiment, measures can be taken to protect the cap against accidental opening. Measures may include recessing the port or the cap, providing protectors, etc.
The kobes can have various constructions and be installed in various ways, as also shown in the above-noted PCT application. For example, in one embodiment, the port 16 in which the kobe is installed can be a hole formed through the wall of the tubular body and the kobe cap, base, etc. can be formed as an insert 2 such as that shown in FIG. 3 and the insert can be installed in port.
In the illustrated embodiment of FIG. 3, insert 2 includes the kobe structures: cap portion 2 a, base 2 b, a channel through the base, which opens at openings 2 c on the base and a shear plane 2 d between the cap portion and the base. Cap portion 2 a is positioned on one end of the insert and the channel openings 2 c are on the opposite end. Insert 2 also includes the inflow controller 4. In this embodiment, controller 4 includes two components. First, filter media 4 a is installed in the channel. The filter media can include, for example, screen, fibers, mesh, etc. As well, fluid control is provided in part by the shape and size of the channel openings 2 c. For example, as shown, the one or more openings may be formed on the end opposite the cap that provides a path for fluid flow into channel of the insert. The openings may themselves provide for inflow control, as by sizing, gates, nozzles or other rate controllers or filter media.
Insert 2 may be installable in a port hole by various means such as, for example, by threaded engagement, using threads 2 e as shown, or by other means such as welding such as inertia welding. Inertia welding welds two pieces of material by creating significant frictional forces between the pieces that the contacting surfaces of the parts are caused to melt and fuse together. For example, the insert may be rotated along its long axis x¹at high speed and may be placed into contact with a port hole of a tubular, which is held substantially stationary, such that the contacting surfaces may be welded together.
It will be appreciated, therefore, that the kobe construction and its mode of installation can be modified in various ways.
FIG. 4 shows another method to open the kobes, this embodiment using a mill 60. If a milling operation is employed to remove ball seats in sliding sleeve valves or other inner diameter ID constrictions or debris, then mill 60 can at the same time be employed to open channels 12 c of the kobes by removing cap portions 12 a. Of course, mill 60 could also be run through tubing string 10 solely for the purpose of opening kobes 12. Once opened, produced fluids can flow through the controller, illustrated here as a screen insert 24, and through opened channel 12 c into the tubing string for flow to surface.
FIGS. 5 a to 5 d show another way of opening kobes 112 in a tubing string 110. A plug can be pumped down to engage against and remove the kobe caps 112 a as it passes. The plug in this illustrated embodiment is a ball-activated cutting sleeve including a cutting sleeve 172 that can be activated into a form of piston when a ball 174 is landed onto an upper end 172 a of the sleeve. Downhole end 172 b of the sleeve may have a tapered edge that acts as a cutter to shear off the caps 112 a′ as it contacts them. Sleeve 172 can reside in the tubing string inner diameter ID and wellbore operations can be conducted through the bore 176 of the sleeve. Sleeve 172 is unaffected by wellbore operations and pressures, until ball 174 is seated therein.
This embodiment relies on pressure, arrows A, to move the plug along and, therefore, to cut off the kobe caps 112 a′ from their bases 112 b. Thus, unless measures are taken to address pressure loss, there may be a limit to the number of kobes that can be opened by the plug until too much pressure is released through the opened kobes that the plug can't be pushed down anymore. Therefore, ports 116 may include an obstruction to at least temporarily hold pressure even after the kobes are opened. For example, limited entry nozzles or removable plugs may be employed to permit pressure to be maintained in the inner diameter ID of tubing string 10 even after a number of kobe caps 112 a′ are removed. Plugs may include burst plugs, erodible discs, etc.
If the ports are suitably obstructed, such as for example, by small plugging pins 178, then the pressure drop through the exposed channel 112 c of the kobe will be minimized, therefore the pressure driven plug can work for long distances.
A plugging pin 178 is a form of plug operated by pressure differentials. FIG. 5 b shows a kobe 112 in a run in position in a tubing string 110, wherein base 112 b of the kobe is installed in port 116 and cap portion 112 a is secured on base 112 b such that channel 112 c is closed. Port 116 also has a fluid flow controller, such as an amount of screening material 124, installed therein. Plugging pin 178 is installed in channel 112 c. Plugging pin 178 creates a seal with the inner walls of channel 112 c and for example, may be sized and/or carry an o-ring 179 to seal with the inner walls. Plugging pin 178 resists fluid flows outwardly from inner diameter ID to outer surface 120 of the tubing string 110 (where P1>P2), but can be expelled from channel 112 c in response to pressures differentials wherein the pressure about outer surface P2 is greater than the pressure P1 in inner diameter. In the illustrated embodiment, when P1 is greater than P2 plugging pin is held in channel 112 c by butting against the screening material 124.
FIG. 5 c shows a kobe after cap portion 112 a′ is removed from its base 112 b, but plugging pin 178 remains plugging fluid flow through channel 112 c of the kobe. Plugging pin 178 therefore substantially holds pressure across port 116. The pressure in inner diameter P1 can exceed P2, but plug remains in channel 112 c as it is stopped against screening material 124. FIG. 4 c shows a kobe in which the production pressure P2 is greater than pressure P1 and produced fluids, arrows F, have forced plugging pin 178 from the channel, thereby opening port 116 to production flow.
Utilizing any of the various options for opening the kobes such as for example any of those shown in FIGS. 2, 4 and 5 a, ports 116 can be opened to permit production of fluids arrows F through the opened ports, including through fluid flow controllers, shown in FIG. 6 as screens 124, and opened channels 112 c, into the tubing string inner diameter ID. Screens 124 present a larger flow area that is reduced by the inner diameter IDk across the kobe port channel 112 c to balance the flow across the wall of tubing string 110. This IDk of the kobe can be adjusted during assembly by selection of the kobes installed in the base tubing string wall.
While FIGS. 1, 2 and 4 to 6 show flow through individual spaced apart ports 116, a kobe sub can include various other port configurations such as those including annular port sections, headers, etc. For example, FIG. 7 shows a kobe sub 210 a port configuration including a plurality of exterior port openings 216 a on outer surface 224. Exterior port openings 216 a open into an annular header area 216 b and inner port openings 216 c extend from annular header area 216 b to inner diameter ID of the sub. The flow area is reduced significantly from area 216 b to openings 216 c and the lateral flow required to pass through the ports creates a pressure drop effect. Such an arrangement of reduced and indirect flow creates a fluid flow controller termed inflow control device (ICD). Port openings 216 a also have screen inserts 224 installed therein such that the fluid flow inwardly through the ports is also controlled to remove oversize materials therefrom.
Kobes 212 are installed in inner port openings 216 c and control the open and closed condition of ports 216. Kobes 212 can be opened by opening their cap portions 212 a.
Sub 210 can be installed in a tubing string 210 a and run into a wellbore 226. As noted above, kobes 212 can be opened by various methods such as by use of a mill 260 passed through the inner diameter ID (FIG. 8) to remove cap portions 212 a and expose channels 212 c to inner diameter ID. As shown in FIG. 9, when channels 212 c of the kobes are opened, the production flow can be screened as it passes from the annulus around the subs outer surface 220 through screen inserts 224 into the annular area 216 b. Once in the annular area, the fluid then flows to channels 212 c of kobes 212 and into the inner diameter ID of the sub.
Other variations are possible. For example, while the exterior port openings 216 a are shown as spaced apart ports, annular openings may be employed for example one or more axially extending, annular openings, as in a wrapped or a sleeve-type screen.
The tubing string referenced above can be a production string, casing, liner, work string, etc. The string may include other components such as frac tools, packers, centralizers, etc. The packers can be of any desired type to seal between the wellbore and the tubing string. In one embodiment, at least one of the first, second and third packer is a solid body packer including multiple packing elements. In such a packer, it is desirable that the multiple packing elements are spaced apart. The apparatus and methods of the present invention can be used in various borehole conditions including open holes, cased holes, vertical holes, horizontal holes, straight holes or deviated holes.
When natural inflow from the well is not economical, the well may require wellbore treatment termed stimulation. This is accomplished by pumping stimulation fluids such as fracturing fluids, acid, cleaning chemicals and/or proppant laden fluids to improve wellbore inflow.
For example, sometimes the well is isolated in segments and one or more segments are individually treated so that concentrated and controlled fluid treatment can be provided along the wellbore by injecting the wellbore stimulation fluids from a tubing string through a port in the segment and into contact with the formation. After wellbore fluid treatment, fluids are sometimes allowed to flow back into the string. The produced fluids may include stimulation fluids and thereafter, fluids produced from the formation.
The method and apparatus of the invention can be adapted to provide for the injection of a wellbore treatment fluid and then reconfiguration to control the inflow of produced fluids.
In one embodiment shown in FIGS. 10 to 12, an apparatus for fluid handling in a borehole, may include a tubular body 310 having a long axis x, a wall 318 including an inner wall surface defining an inner bore ID and an outer wall surface 320 and ends 310 a, 310 b.
An inflow port 316 is opened through wall 318 of the tubular body. A fluid inflow controller 324 is provided in the inflow port to control the flow of fluid into the tubular body through the inflow port. A kobe 312 is installed in inflow port 316 for closing the inflow port, the kobe includes a cap portion 312 a protruding into the inner diameter. The cap portion when intact closes port 316 to fluid flow, but cap 312 a is openable to open fluid flow access through the inflow port from outer wall surface 320 to inner bore ID.
An injection port 380, also called a frac port, may also be opened through wall 318 of the tubular body. The open and closed condition of port 380 may be controlled by a closure 382. Closure 382 may be positioned relative to injection port 380 and may be moveable from (i) a first position closing the injection port (FIG. 10) to (ii) a second position permitting fluid flow through the injection port (FIG. 11). The closure may be moved from the first position to the second position by any of various means. For example, an actuating force may be applied to move closure 382 from the first position to the second position.
Inflow port 316 is separate from injection port 380. For example, inflow port 316 may be axially spaced from injection port 380.
The inflow port is intended for permitting fluid inflow therethrough. As noted above in respect of FIGS. 1 to 10, the inflow port 316 may take various forms and include inflow controllers 324 to control any of various features of the inflowing fluid and kobe 312 can also have various forms. As noted above in FIGS. 1 to 9, there may be a plurality of inflow ports spaced apart on the tubular body such that inflow may be permitted through more than one port. For example, there may be a plurality of ports spaced along the tubular body, each of the plurality of ports having an inflow controller and a sealing, openable kobe.
Injection port 380 is intended for injection of fracturing fluid therethrough from the inner diameter ID to the formation surrounding outer surface 320 the tubular body when the tubular body is installed in a well. Therefore, injection port 380 may have an open diameter or have fluid control means therein such as an outwardly acting nozzle, etc., as desired.
In the illustrated embodiment, closure 382 is a sliding sleeve valve. As such in one embodiment, closure 382 is actuated to slide or rotate to open injection port 380. An actuator for closure 382 in one embodiment may include a manipulation string, such as a tubing string or a wire line, that is run in to engage the sleeve and apply a force to the sleeve to move it to the second position. In yet another embodiment, the sleeve actuator is a motor drive. Of course, other actuators are possible. For example, to facilitate operations the sleeve may be actuated remotely, without the need to trip a work string. In another embodiment, therefore, closure 382 in the form of a sliding sleeve valve as shown, can include a seat 384 formed on an inner diameter thereof and the actuation force may be applied by employing a plug 385 sized to land in and seal against seat 384. Once plug 385 lands, the sleeve and the plug become a piston, such that a pressure differential can be built up across the sleeve and the plug and a fluid pressure force may be applied to move the sleeve causing it to move to the lower pressure side. In yet another embodiment, the closure may be a sleeve of the pressure chamber type, where the closure moves in response to a pressured up condition as permitted by an oppositely acting lower pressure, such as an atmospheric chamber.
The operation of closure 382 may be selected to control the open/closed condition of injection port 380 without affecting inflow port 316. For example, with the sleeve type closure as shown, the sleeve may be installed to ride in an annular recess 386 with an end wall 386 a of the recess acting to limit movement of the sleeve so that it can't move into contact with port 316 or lobe 312.
The tubular body 310, when installed in a well, allows fluid to be injected through injection ports 380 into a wellbore to fluid treat the wellbore and to allow backflowing fluids to be controlled through inflow controlled inflow ports 316. Thus the tubular body can be configured between (i) a run in position, with all ports closed (FIG. 10), (ii) a second position (FIG. 11) with injection port 380 open for fluid treatment of the wellbore while inflow ports 316 are closed, and (iii) a third position (FIG. 12) with inflow ports 316 open and injection port 380 closed, for controlled production of the wellbore.
Tubular body 310 may be continuous or formed of a plurality of sections connected together. In one embodiment, the tubular body includes one or more subs with ends formed for connection into a tubing string, such as a production string, casing, liner, work string, etc.
Tubular body 310 is connectable into a tubing string for placement in a wellbore. The string may include other components such as further frac tools, packers, centralizers, etc. The packers can be of any desired type to seal between the wellbore and the tubing string. In one embodiment, at least one of the first, second and third packer is a solid body packer including multiple packing elements. In such a packer, it is desirable that the multiple packing elements are spaced apart.
With reference to FIG. 13, a tubing string 410 a employing this technology may have a multistage configuration with a plurality of packers 492 installed therealong that are each operable to create an annular seal about the tubing string. When installed in a wellbore 426, the annular seals created by packers 492 fill the annulus between the tubing string and the wellbore wall and create isolated wellbore segments between the packers. The tubing string between adjacent packers can have one or more inflow ports 416 a, 416 b each equipped with kobes 412 and fluid controllers 424. In one embodiment, the inflow ports can have inlet openings (in this embodiment those openings having fluid controllers installed therein) spaced along the string between packers such that access is provided from the annulus to the inner diameter through the plurality along substantially the full length of the wellbore segment. If wellbore stimulation is also of interest, the tubing string may include one or more injection ports 480 a, 480 b between each set of adjacent packers 492. Thus, when the string is installed and the packers are set, each isolated wellbore segment created has one or more inflow ports and possibly one or more injection ports.
The injection ports and the inflow ports may be as described above, for example, injection ports 480 a, 480 b can each include plug-activated closures 482 that are openable to perform hydraulic fracturing jobs and the kobes 412 close inflow ports 416 a, 416 b and provide the tubing string with pressure integrity from either direction during run in, during pressuring up activities, such as pressuring up the tubing for setting the packers, and during fracturing, but allow the ports to be opened selectively, for example, after fracturing is complete. The fluid inflow controllers 424 of inflow ports 416 a, 416 b permit the inflows through the ports to be controlled, for example, with respect to removal of oversize debris and/or with respect to flow characteristics, (i.e. velocity, flow rate, pressure, etc.)
In view of the foregoing there is provided a method for fluid treatment of a borehole, the method comprising: running a tubing string into a wellbore to a desired position for treating the wellbore; opening a frac port by application of a force to a sliding sleeve valve for the frac port; injecting stimulating fluids through the frac port; closing the frac port; opening a fluid inflow control port by opening an inner cap over the fluid control port; and permitting fluid to pass from the wellbore into the tool through the fluid inflow control port.
In one method according to the present invention, the fluid treatment is borehole stimulation using stimulation fluids such as one or more of acid, gelled acid, gelled water, gelled oil, CO₂, nitrogen and any of these fluids containing proppants, such as for example, sand or bauxite. The method can be conducted in an open hole or in a cased hole. In a cased hole, the casing may have to be perforated prior to running the tubing string into the wellbore, in order to provide access to the formation.
In an open hole, the packers may include solid body packers including a solid, extrudable packing element and, in some embodiments, solid body packers include a plurality of extrudable packing elements. The first packer and the second packer can be formed as a solid body packer including multiple packing elements, for example, in spaced apart relation.
The present technology may be useful in wells where inflow control is of interest. For example, a tubing string with a plurality of packer separated string segment, an injection port and with screen media in inflow ports may be employed in a multi-zone fracturing system for wells that require some form of sand control after the frac job. For example, some applications may include in situ production of heavy oil, potentially for cyclic steam or SAGD operations. Alternately, the technology may be appropriate for any poorly consolidated, semi-consolidated wells. Alternately, the technology may be suitable for an application where a hydraulic fracturing job is performed and where formation fines, shale or frac sand may tend to flow back into the liner or to the borehole. In all these applications, it is desirable to prevent the oversize solids from being produced. It is desirable to keep the oversize solids outside in the annulus between the liner and the casing.
Alternately or in addition, the technology may be appropriate for a high velocity producing well. In this type of application, it is desirable to control the rate or volume of fluids being produced. It is desirable to employ a controller that meters production, creates a pressure profile.
In a multistage tubing string, the method can be repeated for each selected stage of the string. For example, a frac job can be pumped through a first stage wherein, the closure for the first stage frac port is opened, as by launching a plug (i.e. dropping a ball) and fluids are injected through that first opened frac port. After that first frac job is pumped, another plug can be launched to open a next frac port and a frac can be pumped through that next frac port. The process can be continued until all of the stages of interest are fraced. The sequence of stages can be opened by launching progressively larger frac plugs, but using sequentially activated seats, etc.
After all stages of interest are fraced, the operator may decide to flow the well back through the frac ports to recover fluid. Alternately, if sand control is of interest, the cap portions of the inflow controlled ports can be opened to allow screened fluid to be produced. The original frac ports may be closed, for example as by moving the closure sleeve or another sleeve to a closed position. The closure sleeves could be closeable, where the sleeve can be actively or will automatically close over the port after an actuating operation, such as drilling to remove the seat.
In each stage, the injection port may be closed and the inflow port may be opened by two separate operations or in one operation. For example, frac port closure sleeves may be shifted to a closed position by a shifting tool, while the caps may be opened by another tool (by impact, milling, etc.). Alternately, the sleeves may be closed and the caps opened in one operation by one tool. For example, the tool may both open the caps and shift the sleeves as the running tool is moved up or down through the string's inner diameter. In one embodiment, for example, everything occurs as a result of a downward movement of a tool, for example, a second sleeve may be provided adjacent the injection port that is pushed down by a tool moved thereby to overlie and close the injection port and that tool may also open the kobes as it passes by the inflow ports. Thus, a string can have a plurality of individual stages that can be individually fraced, but instead of flowing back through the frac ports, flow back can be through the fluid inflow controllers, such as sand control media, ICD, nozzles, gates, etc. when the kobe cap portions for the controllers have been opened. This allows an even distribution of the inflow across the entire stage, for example the entire segment between packers, through multiple, axially spaced apart inflow points. It allows production, while keeping the sand or the fines outside the casing, so that clean fluid is produced. Alternately or in addition, inflow velocities can be controlled at specific points to alleviate concerns, for example in very high rate wells, of erosional issues. Using an appropriate inflow controller, it is possible to control how much inflow comes into each segment of the well. In addition, if as the well is produced, it begins to collapse, as may occur in a SAGD application, in heavy oil or in lightly consolidated sand, such collapse may not have such an adverse impact, as inflow can occur through the length of the segment of the well, from packer to packer, and multiple joints can be run with installed fluid controllers such as sand control media.
The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments without departing from the spirit or scope of the invention. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article “a” or “an” is not intended to mean “one and only one” unless specifically so stated, but rather “one or more”. All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are know or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims. No claim element is to be construed under the provisions of 35 USC 112, sixth paragraph, unless the element is expressly recited using the phrase “means for” or “step for”.

Claims

1. A kobe sub comprising: a tubular body connectable into a wellbore tubing string, the tubular body including a wall including an outer surface and an inner surface defining an inner bore and a port through the wall; a kobe installed in the port with a cap portion accessible in the inner bore, a base mounted in the port and connected to the cap portion, a channel extending through the base and closed by the cap portion; and an inflow controller positioned to control fluid flowing through the channel toward the inner bore when the cap portion is opened.

2. The kobe sub of claim 1 wherein the inflow controller is selected to filter oversize solids from the fluid flowing.

3. The kobe sub of claim 1 wherein the inflow controller is selected to control flow characteristics of the fluid flowing.

4. The kobe sub of claim 1 wherein the inflow controller is positioned in the channel.

5. The kobe sub of claim 1 wherein the inflow controller is a part of the channel.

6. The kobe sub of claim 1 further comprising a tool sized to move through the inner bore to contact and open the cap portion.

7. The kobe sub of claim 6 wherein the tool is a cutter sleeve installed in the inner bore.

8. The kobe sub of claim 1 further comprising an injection port through the wall and a closure for the injection port moveable between a closed position closing the injection port and an open position retracted from the injection port.

9. A tubing string system for installation in a wellbore comprising: a tubular body including a tubular wall with an outer surface and an inner surface defining an inner bore and a port through the tubular wall; a kobe installed in the port with a cap portion accessible in the inner bore, a base mounted in the port and connected to the cap portion, a channel extending through the base and closed by the cap portion; and an inflow controller positioned to control fluid flowing through the channel toward the inner bore when the cap portion is opened; and a port opening tool for opening the cap portion.

10. The tubing string system of claim 9 wherein the inflow controller is selected to filter oversize solids from the fluid flowing.

11. The tubing string system of claim 9 wherein the inflow controller is selected to control flow characteristics of the fluid flowing.

12. The tubing string system of claim 9 wherein the inflow controller is positioned in the channel.

13. The tubing string system of claim 9 wherein the inflow controller is a part of the channel.

14. The tubing string system of claim 9 wherein the port opening tool is a cutter sleeve installed in the inner bore.

15. The tubing string system of claim 9 further comprising an injection port through the wall and a closure for the injection port moveable between a closed position closing the injection port and an open position retracted from the injection port.

16. The tubing string system of claim 15 wherein the closure is moveable to the open position without also opening the cap portion.

17. The tubing string system of claim 9 further comprising a first packer positioned uphole from the port and a second packer positioned downhole from the port.

18. The tubing string system of claim 9 further comprising a second stage of the tubing string positioned uphole from the first packer and including a second port through the tubular wall; a second kobe installed in the second port with a second cap portion accessible in the inner bore, a second base mounted in the second port and connected to the second cap portion, a second channel extending through the second base and closed by the second cap portion; and a second inflow controller positioned to control fluid flowing through the second channel toward the inner bore when the second cap portion is opened.

19. The tubing string system of claim 18 further comprising in the second stage: a second injection port through the wall and a second closure for the second injection port moveable between a closed position closing the injection port and an open position retracted from the injection port.

20. A method for forming a fluid channel through a tubing string wall, the method comprising: installing a tubing string in a wellbore, the tubing string including a tubular wall including an outer surface and an inner surface defining an open inner bore and a port through the wall; a kobe installed in the port with a cap portion accessible in the inner bore, a base mounted in the port and connected to the cap portion, a channel extending through the base and closed by the cap portion; and an inflow controller positioned to control fluid flowing through the channel toward the inner bore when the cap portion is opened; manipulating a port opening tool in the inner bore to open the cap portion and to allow fluid flow through the inflow controller and the channel into the inner bore.

21. The method of claim 20 wherein manipulating includes running a mill through the inner bore.

22. The method of claim 20 wherein manipulating includes running a cutter sleeve through the inner bore.

23. The method of claim 20 wherein manipulating includes running a sleeve shifting tool through the inner bore.

24. The method of claim 20 wherein manipulating also closes an injection port in the tubing string.

25. The method of claim 20 further comprising opening an injection port in the tubing string and injecting wellbore treatment fluid therethrough to treat the formation.

26. The method of claim 20 further comprising pressuring up the string before the manipulating the port opening tool.

27. A method for fluid treatment of a borehole, the method comprising: running a tubing string into a wellbore to a desired position for treating the wellbore; opening a frac port by application of a force to a closure for the frac port; injecting stimulating fluids through the frac port; closing the frac port; opening a fluid inflow control port by opening an inner cap over the fluid inflow control port; and permitting fluid to pass from the wellbore into the tool through the fluid inflow control port.

28. The method of claim 27 wherein opening a fluid inflow control port includes running a mill through the inner bore.

29. The method of claim 27 wherein opening a fluid inflow control port includes running a cutter sleeve through the inner bore.

30. The method of claim 27 wherein opening a fluid inflow control port includes running a sleeve shifting tool through the inner bore.

31. The method of claim 27 wherein opening a fluid inflow control port also closes an injection port in the tubing string.

32. The method of claim 27 further comprising pressuring up the string before opening the frac port.