WO2012174662A1 - Raccord kobe avec commande d'afflux, colonne de tubage de trous de forage, et procédé - Google Patents

Raccord kobe avec commande d'afflux, colonne de tubage de trous de forage, et procédé Download PDF

Info

Publication number
WO2012174662A1
WO2012174662A1 PCT/CA2012/050412 CA2012050412W WO2012174662A1 WO 2012174662 A1 WO2012174662 A1 WO 2012174662A1 CA 2012050412 W CA2012050412 W CA 2012050412W WO 2012174662 A1 WO2012174662 A1 WO 2012174662A1
Authority
WO
WIPO (PCT)
Prior art keywords
port
tubing string
cap portion
inner bore
fluid
Prior art date
Application number
PCT/CA2012/050412
Other languages
English (en)
Inventor
Daniel Jon Themig
Robert Joe Coon
Original Assignee
Packers Plus Energy Services Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Packers Plus Energy Services Inc. filed Critical Packers Plus Energy Services Inc.
Priority to EP12803334.7A priority Critical patent/EP2721247A4/fr
Priority to US13/883,218 priority patent/US20140151052A1/en
Priority to BR112013032427A priority patent/BR112013032427A2/pt
Priority to CA2837771A priority patent/CA2837771A1/fr
Publication of WO2012174662A1 publication Critical patent/WO2012174662A1/fr

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/063—Valve or closure with destructible element, e.g. frangible disc
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/18—Pipes provided with plural fluid passages
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B29/00—Cutting or destroying pipes, packers, plugs or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windows; Deforming of pipes in boreholes or wells; Reconditioning of well casings while in the ground
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/14—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/2605—Methods for stimulating production by forming crevices or fractures using gas or liquefied gas
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/27—Methods for stimulating production by forming crevices or fractures by use of eroding chemicals, e.g. acids

Definitions

  • the invention is directed to a wellbore apparatus and method and, in particular a kobe sub, wellbore tubing string and method.
  • 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.
  • 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.
  • 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.
  • the produced fluids may require flow rate control, as by use of chokes including devices called inflow control devices (ICD).
  • ICD inflow control devices
  • 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.
  • a method for forming a fluid channel through a tubing string wall 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.
  • 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.
  • a method for fluid treatment of a borehole 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.
  • Figure 1 is a sectional view along the long axis of kobe sub
  • Figure 2 is a sectional view along the kobe sub of Figure 1 undergoing a port opening operation
  • Figure 3 is a perspective view of a fluid control port insert useful in the present invention.
  • Figure 4 is a sectional view along the kobe sub of Figure 1 undergoing another type of port opening operation
  • Figure 5 a is a sectional view along a kobe sub undergoing another type of port opening operation
  • Figures 5b to 5d are a series of drawings showing a kobe opening operation
  • Figure 6 is a sectional view along the kobe sub of Figure 5 with its ports open
  • Figure 7 is a sectional view along the long axis of another kobe sub;
  • Figure 8 is a sectional view along the kobe sub of Figure 7 undergoing a port opening operation
  • Figure 9 is a sectional view along the kobe sub of Figure 7 with its ports open;
  • Figure 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;
  • Figure 1 1 is a sectional view along the sub of Figure 10 with the sleeve in a position allowing fluid flow through injection ports;
  • Figure 12 is a sectional view along the sub of Figure 10 allowing fluid flow through fluid inflow control ports;
  • Figure 13 is a sectional view along a tubing string in a wellbore.
  • Figure 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 10a, a lower end 1 Ob 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.
  • 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.
  • ports 16 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 12a, a base 12b attached to the cap portion, and a channel 12c that extends through the base.
  • the kobe can be mounted at its base 12b in a port with its cap portion 12a protruding beyond the surrounding wall surface defining inner diameter ID.
  • the base can be sealed to the port walls, such that channel 12c creates the flow path through the port.
  • Cap portion 12a while it is in place on the base, seals channel 12c against fluid flow therethrough. Cap portion 12a, 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”.
  • the kobe includes a weakened area 12d between cap portion 12a and base 12b that facilitates opening removal by separation of the cap portion from the base, when force is applied to cap portion 12a.
  • Kobe sub 10 may be connected into a wellbore string for installation into a well.
  • its ends 10a, 10b may be formed for connection in line with other tubulars.
  • its ends may be threaded and formed as pins or boxes for typical threaded connection to other tubulars.
  • Kobe sub 10 illustrated in Figure 1 has ports 16 particularly suited to controlling fluid flows therethrough.
  • 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.
  • 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.
  • controller 24 For each port, when cap portion 12a is in place, flow is prevented through channel 12c and therefore controller 24 is inactive. However, when cap portion 12a is opened, the fluid inflow controller acts on the fluids passing inwardly through the port through channel 12c.
  • Figure 1 shows sub 10 with all ports 16 closed by their kobes. This is the run in state of the tool.
  • controllers 24, in this embodiment screen inserts are installed with kobes 12 sealing them from the ID of the tubing.
  • the tubing at the location of sub 10 has a full pressure rating, substantially equal to a section of standard tubing without ports.
  • 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.
  • the kobes can be opened to permit flow through the ports.
  • Various methods can be employed to open the ports to flow therethrough.
  • 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.
  • Figure 2 shows sub 10 after it has been connected into a tubing string and installed in a wellbore, as indicated by wall 26.
  • the operator may wish to open the ports by opening cap portions 12a.
  • 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 12a as the keys pass ports 16.
  • Shearing cap portions 12a' which are accessible in the ID of the tubing string, from their bases 12b, opens channels 12c for fluid communication between the ID and an annulus 56 between wall 26 and outer surface 20 of the tubing string.
  • cap portions 12a' 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.
  • 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.
  • 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.
  • 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.
  • 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 Figure 3 and the insert can be installed in port.
  • insert 2 includes the kobe structures: cap portion 2a, base 2b, a channel through the base, which opens at openings 2c on the base and a shear plane 2d between the cap portion and the base.
  • Cap portion 2a is positioned on one end of the insert and the channel openings 2c are on the opposite end.
  • Insert 2 also includes the inflow controller 4.
  • controller 4 includes two components.
  • filter media 4a is installed in the channel.
  • the filter media can include, for example, screen, fibers, mesh, etc.
  • fluid control is provided in part by the shape and size of the channel openings 2c.
  • 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 2e 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.
  • the insert may be rotated along its long axis x l at 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.
  • Figure 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 12c of the kobes by removing cap portions 12a. 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 12c into the tubing string for flow to surface.
  • FIGS 5a to 5d 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 112a 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 172a of the sleeve.
  • Downhole end 172b of the sleeve may have a tapered edge that acts as a cutter to shear off the caps 1 12a' 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.
  • ports 1 16 may include an obstruction to at least temporarily hold pressure even after the kobes are opened.
  • 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 1 12a' are removed.
  • Plugs may include burst plugs, erodible discs, etc.
  • the ports are suitably obstructed, such as for example, by small plugging pins 178, then the pressure drop through the exposed channel 112c 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.
  • Figure 5b shows a kobe 112 in a run in position in a tubing string 110, wherein base 112b of the kobe is installed in port 116 and cap portion 112a is secured on base 1 12b such that channel 112c 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 1 12c. Plugging pin 178 creates a seal with the inner walls of channel 1 12c 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 1 10 (where P1>P2), but can be expelled from channel 112c in response to pressures differentials wherein the pressure about outer surface P2 is greater than the pressure PI in inner diameter.
  • P1>P2 the pressure about outer surface P2 is greater than the pressure PI in inner diameter.
  • Figure 5c shows a kobe after cap portion 1 12a' is removed from its base 1 12b, but plugging pin 178 remains plugging fluid flow through channel 1 12c of the kobe. Plugging pin 178 therefore substantially holds pressure across port 116. The pressure in inner diameter PI can exceed P2, but plug remains in channel 112c as it is stopped against screening material 124.
  • Figure 4c shows a kobe in which the production pressure P2 is greater than pressure PI and produced fluids, arrows F, have forced plugging pin 178 from the channel, thereby opening port 116 to production flow.
  • ports 116 can be opened to permit production of fluids arrows F through the opened ports, including through fluid flow controllers, shown in Figure 6 as screens 124, and opened channels 112c, 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 112c 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.
  • a kobe sub can include various other port configurations such as those including annular port sections, headers, etc.
  • Figure 7 shows a kobe sub 210 a port configuration including a plurality of exterior port openings 216a on outer surface 224. Exterior port openings 216a open into an annular header area 216b and inner port openings 216c extend from annular header area 216b to inner diameter ID of the sub. The flow area is reduced significantly from area 216b to openings 216c 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 216a also have screen inserts 224 installed therein such that the fluid flow inwardly through the ports is also controlled to remove oversize materials therefrom.
  • ICD inflow control device
  • Kobes 212 are installed in inner port openings 216c and control the open and closed condition of ports 216. Kobes 212 can be opened by opening their cap portions 212a.
  • Sub 210 can be installed in a tubing string 210a and run into a wellbore 226.
  • kobes 212 can be opened by various methods such as by use of a mill 260 passed through the inner diameter ID ( Figure 8) to remove cap portions 212a and expose channels 212c to inner diameter ID.
  • Figure 9 when channels 212c 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 216b. Once in the annular area, the fluid then flows to channels 212c of kobes 212 and into the inner diameter ID of the sub.
  • 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.
  • 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.
  • the well may require wellbore treatment termed stimulation.
  • stimulation fluids such as fracturing fluids, acid, cleaning chemicals and/or proppant laden fluids to improve wellbore inflow.
  • 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.
  • 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 310a, 310b.
  • 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 312a protruding into the inner diameter. The cap portion when intact closes port 316 to fluid flow, but cap 312a 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 ( Figure 10) to (ii) a second position permitting fluid flow through the injection port ( Figure 1 1).
  • 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.
  • inflow port 316 may be axially spaced from injection port 380.
  • the inflow port is intended for permitting fluid inflow therethrough.
  • 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,
  • 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.
  • 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.
  • the sleeve actuator is a motor drive.
  • other actuators are possible. For example, to facilitate operations the sleeve may be actuated remotely, without the need to trip a work string.
  • 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.
  • 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.
  • closure 382 may be selected to control the open/closed condition of injection port 380 without affecting inflow port 316.
  • the sleeve type closure as shown, the sleeve may be installed to ride in an annular recess 386 with an end wall 386a of the recess acting to limit movement of the sleeve so that it can't move into contact with port 316 or kobe 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.
  • the tubular body can be configured between (i) a run in position, with all ports closed ( Figure 10), (ii) a second position ( Figure 11) with injection port 380 open for fluid treatment of the wellbore while inflow ports 316 are closed, and (iii) a third position ( Figure 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.
  • 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.
  • 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.
  • a tubing string 410a 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.
  • 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 416a, 416b each equipped with kobes 412 and fluid controllers 424.
  • 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.
  • the tubing string may include one or more injection ports 480a, 480b between each set of adjacent packers 492.
  • each isolated wellbore segment created has one or more inflow ports and possibly one or more injection ports.
  • injection ports 480a, 480b can each include plug-activated closures 482 that are openable to perform hydraulic fracturing jobs and the kobes 412 close inflow ports 416a, 416b 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 416a, 416b 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.)
  • a method for fluid treatment of a borehole 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.
  • the fluid treatment is borehole stimulation using stimulation fluids such as one or more of acid, gelled acid, gelled water, gelled oil, C0 2 , 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.
  • the casing may have to be perforated prior to running the tubing string into the wellbore, in order to provide access to the formation.
  • 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.
  • 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.
  • some applications may include in situ production of heavy oil, potentially for cyclic steam or SAGD operations.
  • the technology may be appropriate for any poorly consolidated, semi-consolidated wells.
  • 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.
  • the technology may be appropriate for a high velocity producing well.
  • 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.
  • a plug i.e. dropping a ball
  • 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.
  • the operator may decide to flow the well back through the frac ports to recover fluid.
  • 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.
  • the injection port may be closed and the inflow port may be opened by two separate operations or in one operation.
  • 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.).
  • the sleeves may be closed and the caps opened in one operation by one tool.
  • 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.
  • 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.
  • 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.
  • 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.

Landscapes

  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Mechanical Engineering (AREA)
  • Pipe Accessories (AREA)

Abstract

L'invention concerne un raccord Kobe comportant un kobe installé dans un orifice du raccord, le kobe comportant une partie de chapeau accessible dans le trou intérieur, une base montée dans l'orifice et connectée à la partie de chapeau, un canal s'étendant à travers la base et fermé par la partie de chapeau ; et un régulateur d'afflux positionné de manière à réguler le fluide s'écoulant à travers le canal vers le trou intérieur lorsque la partie de chapeau est ouverte ; et un outil d'ouverture d'orifice pour ouvrir la partie de chapeau. Le kobe peut être utilisé avec un orifice de fracturation.
PCT/CA2012/050412 2011-06-20 2012-06-20 Raccord kobe avec commande d'afflux, colonne de tubage de trous de forage, et procédé WO2012174662A1 (fr)

Priority Applications (4)

Application Number Priority Date Filing Date Title
EP12803334.7A EP2721247A4 (fr) 2011-06-20 2012-06-20 Raccord kobe avec commande d'afflux, colonne de tubage de trous de forage, et procédé
US13/883,218 US20140151052A1 (en) 2011-06-20 2012-06-20 Kobe sub with inflow control, wellbore tubing string and method
BR112013032427A BR112013032427A2 (pt) 2011-06-20 2012-06-20 sub-kobe com controle de influxo, coluna de tubulação de furo de poço e método
CA2837771A CA2837771A1 (fr) 2011-06-20 2012-06-20 Raccord kobe avec commande d'afflux, colonne de tubage de trous de forage, et procede

Applications Claiming Priority (6)

Application Number Priority Date Filing Date Title
US201161499071P 2011-06-20 2011-06-20
US61/499,071 2011-06-20
US201161562556P 2011-11-22 2011-11-22
US61/562,556 2011-11-22
US201261613299P 2012-03-20 2012-03-20
US61/613,299 2012-03-20

Publications (1)

Publication Number Publication Date
WO2012174662A1 true WO2012174662A1 (fr) 2012-12-27

Family

ID=47421954

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/CA2012/050412 WO2012174662A1 (fr) 2011-06-20 2012-06-20 Raccord kobe avec commande d'afflux, colonne de tubage de trous de forage, et procédé

Country Status (5)

Country Link
US (1) US20140151052A1 (fr)
EP (1) EP2721247A4 (fr)
BR (1) BR112013032427A2 (fr)
CA (1) CA2837771A1 (fr)
WO (1) WO2012174662A1 (fr)

Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2015130258A1 (fr) * 2014-02-25 2015-09-03 Halliburton Energy Services, Inc. Bouchon cassant pour commander l'écoulement au travers d'une complétion
FR3061232A1 (fr) * 2016-12-23 2018-06-29 Halliburton Energy Services, Inc. Outil de puits ayant un collier amovible pour permettre l'ecoulement de fluide de production

Families Citing this family (33)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP2521839A1 (fr) 2010-01-04 2012-11-14 Packers Plus Energy Services Inc. Appareil et procédé de traitement de puits de forage
EP2619405A1 (fr) 2010-09-23 2013-07-31 Packers Plus Energy Services Inc. Appareil et procédé de traitement de fluide d'un puits
EP2640930A1 (fr) * 2010-11-19 2013-09-25 Packers Plus Energy Services Inc. Raccord kobe, appareil à colonne de production de puits de forage, et procédé
US9523261B2 (en) * 2011-08-19 2016-12-20 Weatherford Technology Holdings, Llc High flow rate multi array stimulation system
US9416651B2 (en) * 2013-07-12 2016-08-16 Saudi Arabian Oil Company Surface confirmation for opening downhole ports using pockets for chemical tracer isolation
WO2015017638A1 (fr) 2013-07-31 2015-02-05 Schlumberger Canada Limited Système et procédé de contrôle du sable
US9567826B2 (en) 2015-04-28 2017-02-14 Thru Tubing Solutions, Inc. Flow control in subterranean wells
US11851611B2 (en) 2015-04-28 2023-12-26 Thru Tubing Solutions, Inc. Flow control in subterranean wells
WO2016176181A1 (fr) * 2015-04-28 2016-11-03 Thru Tubing Solutions, Inc. Régulation de débit dans des puits souterrains
US10513653B2 (en) 2015-04-28 2019-12-24 Thru Tubing Solutions, Inc. Flow control in subterranean wells
US9567824B2 (en) 2015-04-28 2017-02-14 Thru Tubing Solutions, Inc. Fibrous barriers and deployment in subterranean wells
US10774612B2 (en) 2015-04-28 2020-09-15 Thru Tubing Solutions, Inc. Flow control in subterranean wells
US10655427B2 (en) 2015-04-28 2020-05-19 Thru Tubing Solutions, Inc. Flow control in subterranean wells
US10233719B2 (en) 2015-04-28 2019-03-19 Thru Tubing Solutions, Inc. Flow control in subterranean wells
US9523267B2 (en) 2015-04-28 2016-12-20 Thru Tubing Solutions, Inc. Flow control in subterranean wells
US10851615B2 (en) 2015-04-28 2020-12-01 Thru Tubing Solutions, Inc. Flow control in subterranean wells
US9708883B2 (en) 2015-04-28 2017-07-18 Thru Tubing Solutions, Inc. Flow control in subterranean wells
US9816341B2 (en) 2015-04-28 2017-11-14 Thru Tubing Solutions, Inc. Plugging devices and deployment in subterranean wells
US9567825B2 (en) 2015-04-28 2017-02-14 Thru Tubing Solutions, Inc. Flow control in subterranean wells
US10641069B2 (en) 2015-04-28 2020-05-05 Thru Tubing Solutions, Inc. Flow control in subterranean wells
US9745820B2 (en) 2015-04-28 2017-08-29 Thru Tubing Solutions, Inc. Plugging device deployment in subterranean wells
CN106468157B (zh) * 2015-08-21 2018-12-28 中国石油化工股份有限公司 投球式压裂滑套和压裂管柱
RU2597416C1 (ru) * 2015-10-06 2016-09-10 Эдуард Фёдорович Соловьёв Скважинный фильтр
NO340798B1 (en) * 2016-01-04 2017-06-19 Interwell Technology As Plugging device with frangible glass body having a breakable neck
WO2017132744A1 (fr) 2016-02-03 2017-08-10 Tartan Completion Systems Inc. Ensemble bouchon de rupture avec pièce rapportée d'étranglement, outil de fracturation et procédé de fracturation l'utilisant
US9920589B2 (en) 2016-04-06 2018-03-20 Thru Tubing Solutions, Inc. Methods of completing a well and apparatus therefor
WO2018200688A1 (fr) 2017-04-25 2018-11-01 Thru Tubing Solutions, Inc. Obturation d'ouvertures indésirables dans des récipients de fluide
CA3058512C (fr) 2017-04-25 2022-06-21 Thru Tubing Solutions, Inc. Obturation d'ouvertures indesirables dans des conduits de fluide
CN111094691B (zh) * 2017-08-30 2023-01-24 斯伦贝谢技术有限公司 井下换能器组件中的压力范围控制
US10822918B2 (en) * 2018-03-21 2020-11-03 Baker Hughes, A Ge Company, Llc Sand control screens for hydraulic fracture and method
WO2019231658A1 (fr) * 2018-05-31 2019-12-05 Vertice Oil Tools Procédés et systèmes pour la cimentation à travers des crépines
US11566471B2 (en) * 2020-11-02 2023-01-31 Baker Hughes Oilfield Operations Llc Selectively openable communication port for a wellbore drilling system
US20220389792A1 (en) * 2021-06-07 2022-12-08 Halliburton Energy Services, Inc. Isolation sleeve with high-expansion seals for passing through small restrictions

Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US958100A (en) * 1909-09-24 1910-05-17 Harry R Decker Strainer for oil and water wells.
US2287076A (en) * 1940-12-26 1942-06-23 Standard Oil Dev Co Gas port coupling
US3924677A (en) * 1974-08-29 1975-12-09 Harry Koplin Device for use in the completion of an oil or gas well
GB2258478A (en) * 1991-08-05 1993-02-10 Tcf Tool Inc Wellbore isolation system.
US20030127227A1 (en) * 2001-11-19 2003-07-10 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
WO2010025150A2 (fr) * 2008-08-29 2010-03-04 Halliburton Energy Services, Inc. Ensemble crible de contrôle de sable et son procédé d’utilisation

Family Cites Families (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3095040A (en) * 1961-06-30 1963-06-25 Bramlett Oil Field Service Inc Access valve for completing oil wells
US5355956A (en) * 1992-09-28 1994-10-18 Halliburton Company Plugged base pipe for sand control
US6772837B2 (en) * 2001-10-22 2004-08-10 Halliburton Energy Services, Inc. Screen assembly having diverter members and method for progressively treating an interval of a welibore
US8167047B2 (en) * 2002-08-21 2012-05-01 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
US7451815B2 (en) * 2005-08-22 2008-11-18 Halliburton Energy Services, Inc. Sand control screen assembly enhanced with disappearing sleeve and burst disc

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US958100A (en) * 1909-09-24 1910-05-17 Harry R Decker Strainer for oil and water wells.
US2287076A (en) * 1940-12-26 1942-06-23 Standard Oil Dev Co Gas port coupling
US3924677A (en) * 1974-08-29 1975-12-09 Harry Koplin Device for use in the completion of an oil or gas well
GB2258478A (en) * 1991-08-05 1993-02-10 Tcf Tool Inc Wellbore isolation system.
US20030127227A1 (en) * 2001-11-19 2003-07-10 Packers Plus Energy Services Inc. Method and apparatus for wellbore fluid treatment
WO2010025150A2 (fr) * 2008-08-29 2010-03-04 Halliburton Energy Services, Inc. Ensemble crible de contrôle de sable et son procédé d’utilisation

Cited By (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2015130258A1 (fr) * 2014-02-25 2015-09-03 Halliburton Energy Services, Inc. Bouchon cassant pour commander l'écoulement au travers d'une complétion
US10030472B2 (en) 2014-02-25 2018-07-24 Halliburton Energy Services, Inc. Frangible plug to control flow through a completion
FR3061232A1 (fr) * 2016-12-23 2018-06-29 Halliburton Energy Services, Inc. Outil de puits ayant un collier amovible pour permettre l'ecoulement de fluide de production
GB2571464B (en) * 2016-12-23 2021-09-15 Halliburton Energy Services Inc Well tool having a removable collar for allowing production fluid flow
US11193350B2 (en) 2016-12-23 2021-12-07 Halliburton Energy Services, Inc. Well tool having a removable collar for allowing production fluid flow
GB2596236A (en) * 2016-12-23 2021-12-22 Halliburton Energy Services Inc Well tool having a removable collar for allowing production fluid to flow
GB2596236B (en) * 2016-12-23 2022-03-30 Halliburton Energy Services Inc Well tool having a removable collar for allowing production fluid to flow

Also Published As

Publication number Publication date
EP2721247A1 (fr) 2014-04-23
CA2837771A1 (fr) 2012-12-27
BR112013032427A2 (pt) 2017-01-17
EP2721247A4 (fr) 2015-11-11
US20140151052A1 (en) 2014-06-05

Similar Documents

Publication Publication Date Title
US20140151052A1 (en) Kobe sub with inflow control, wellbore tubing string and method
US9909392B2 (en) Wellbore frac tool with inflow control
US10487626B2 (en) Fracturing valve and fracturing tool string
EP2351904B1 (fr) Procédés et appareil pour outil d'extraction
RU2733998C2 (ru) Устройство, системы и способы многоступенчатой стимуляции
EP2611988B1 (fr) Outil d'isolation multifonction et procédé d'utilisation correspondant
CA2999324C (fr) Outillage de fond avec securite pour debris, et methode d'utilisation
US8397820B2 (en) Method and apparatus for wellbore fluid treatment
US20130180721A1 (en) Downhole Fluid Treatment Tool
US20140345876A1 (en) Inflow control solutions for wellbores
US10947815B2 (en) Tool assembly with collet and shiftable valve and process for directing fluid flow in a wellbore
CA2873541A1 (fr) Vanne de fracturation et train d'outils de fracturation
AU2013403420C1 (en) Erosion resistant baffle for downhole wellbore tools

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 12803334

Country of ref document: EP

Kind code of ref document: A1

WWE Wipo information: entry into national phase

Ref document number: 13883218

Country of ref document: US

ENP Entry into the national phase

Ref document number: 2837771

Country of ref document: CA

REEP Request for entry into the european phase

Ref document number: 2012803334

Country of ref document: EP

WWE Wipo information: entry into national phase

Ref document number: 2012803334

Country of ref document: EP

NENP Non-entry into the national phase

Ref country code: DE

REG Reference to national code

Ref country code: BR

Ref legal event code: B01A

Ref document number: 112013032427

Country of ref document: BR

ENP Entry into the national phase

Ref document number: 112013032427

Country of ref document: BR

Kind code of ref document: A2

Effective date: 20131217