CN101365863A - Pressure suppression device and method of use - Google Patents

Abstract

Moveable and split packer cups for use above a conventional coiled tubing fracturing or stimulation tool are described as well as methods for running these tools into a wellbore. These devices can be used for extended stimulation intervals with coiled tubing, as well as for a secondary pressure containment to avoid pressure communication with uphole formations or perforations.

Description

Pressure suppression device and method of use

Cross References to Related Applications

This application claims priority to Canadian Patent Applications No. 2,532,295, filed January 6, 2006, and Canadian Patent Applications No. 2,552,072, filed July 14, 2006.

technical field

This invention relates to the use of coiled tubing to hydraulically fracture or stimulate subterranean formations for improved oil and gas production, and more particularly to pressure suppression devices.

Background technique

Hydraulic fracturing, or stimulation of subterranean rock formations to increase oil and gas production has become routine in the petroleum industry. In hydraulic fracturing, a fracturing fluid is injected through a wellbore into a rock formation at a pressure and flow rate sufficient to overcome excess gravity stresses and initiate fracture of the rock formation. The fracturing fluid may be a water-based liquid, an oil-based liquid, a liquefied gas such as (but not limited to) carbon dioxide, a dry gas such as (but not limited to) nitrogen, or a combination of liquefied and dry gas, or these Or some combination of any of the other fluids. Most commonly, proppants are introduced into the fracturing fluid, which act to prevent the created fractures from closing back when the pressure is released. The proppant is suspended in the fracturing fluid and delivered into the fracture. Proppants in use contain 20 to 40 mesh size sand, ceramics, and other materials that provide highly permeable channels within the fracture to allow oil or gas to flow from the formation to the wellbore in relatively large flows.

Stimulation techniques may include the introduction of acids to dissolve formation or drilling contaminants, or introduction of solvent fluids to remove paraffin or waxy buildup, or other such techniques.

Oil or gas production can be significantly increased through the use of these techniques.

Hydraulic fracturing using coiled tubing is a common operation. It typically employs a bottom hole assembly comprising opposing sets of one or more pressure containment devices (such as fracture caps or packer caps) secured to the wall, typically On a section of pipe that is thicker than the coil string. The distance between the two sets of opposing frac cups determines the length of the formation interval that will be fractured by securing the cups to the bottom hole assembly. In this type of operation, it is common that the length of the interval to be fractured is limited by the distance between the frac cups, which itself may be limited by the length of the lubricator and/or the height of the crane.

In a typical operation, the well needs to be left intact, which means that the well is flowed but not damaged with water or heavier fluids when the operation is performed. In the case of such undisturbed well operations, coiled tubing is considered to have a significant advantage over spliced tubing operations because the surface pressure is continuously controlled when the coiled tubing is moved in and out of the well and after the tool is in the wellbore No joints are formed on the strings.

To achieve undisturbed well operation, tools for fracturing are lubricated into and out of the wellbore during which the tools are attached to coiled tubing and housed in a length of pressure integral tubing (known as a lubricator) and Attached to the wellbore above a coil blowout preventer (BOP), which itself is attached to a pressure control valve commonly referred to as the main valve. After connecting the lubricator housing the coiled fracturing tool and coil to the main valve, the lubricator system is tested to ensure it is maintaining wellbore pressure without leaking. Well pressure is then suppressed by a coil puller or stuffer box between the lubricator and the injector. After the pressure integrity of the system has been established by testing, the main valve can be opened and the fracturing tool and coils transported into the wellbore to the desired depth for the fracturing operation, and the entire operation is carried out in-situ.

In performing these operations, it is common for fractures initiated in one or more zones to perforate behind the sleeve to one or more upper zones through open perforations in the sleeve, thereby reducing the efficiency of current fracture treatment And also potentially impairs future fracture treatments on one or more upper zones.

Contents of the invention

Accordingly, in one aspect, the present invention relates to a method of pressure suppression in a wellbore comprising the steps of: providing coiled tubing; providing a moveable pressure suppression device on the tubing; inserting the tubing into the wellbore to a first depth while placing Maintaining the moveable pressure containment device at the surface and passing the pipe through the moveable pressure containment device; securing the moveable pressure containment device in position on the pipe; and inserting the pipe into the wellbore to a second depth. The method may further comprise the bottom hole assembly, and wherein the first pressure suppression device is secured to the bottom hole assembly with at least one non-removable pressure suppression device secured to the bottom hole assembly. The bottom hole assembly may be a fracturing tool. The movable pressure suppression device may include a lock for securing the movable pressure suppression device to the tubing such that the tubing is not permitted to pass through the pressure suppression device when the tubing is inserted into the wellbore to the second depth. The method can be used for primary, secondary and tertiary pressure suppression.

In another aspect, the invention relates to a method of pressure suppression in a wellbore comprising the steps of: providing coiled tubing; transporting the coiled tubing into the wellbore to a first depth; attaching a pressure suppression device to a pipe at the surface and transporting the coiled tubing into the wellbore to a second depth, and the method may include a bottom hole assembly connected to the tubing. The bottom hole assembly may include at least one non-removable pressure suppression device. The device may be a split cup.

In another aspect, the invention relates to a method of pressure suppression in a wellbore comprising the steps of: providing coiled tubing with a first fixed pressure suppression cup on the tubing; providing a movable pressure suppression cup on the tubing; transporting the tubing into the wellbore to a first depth while maintaining the movable pressure containment cup at the surface and passing the pipe through the movable pressure cup; securing the movable cup in position on the pipe; and transporting the pipe into the wellbore to a second depth .

In yet another aspect, the present invention relates to a method of pressure suppression in a wellbore comprising the steps of: providing coiled tubing with a first fixed pressure suppression cup thereon; transporting the tubing into the wellbore to a first depth; providing pressure restraining and securing the member in a position on the pipe other than the pipe end; and conveying the pipe into the wellbore to a second depth.

In another aspect, the invention relates to a fluid containment device for sealing fluid in a wellbore, comprising: a sleeve for placing over a coiled tubing; and a releasable locking member for locking the device on the coil whereby the coil can be passed through the device when the locking member is in the unlocked position. The device can be a packer cup or a frac cup.

In another aspect, the invention is directed to a coil assembly that includes a coil and a movable pressure containment member on the coil. The assembly may comprise a first fixed pressure suppression cup on the tube along the downwardly facing aperture of the movable suppression member.

In another aspect, the invention relates to a fluid containment cup for containing fluid in a wellbore comprising two casing halves.

Description of drawings

The invention will now be described in more detail hereinafter with reference to the accompanying drawings, in which embodiments of the invention are illustrated and in which:

Figure 1 is a side view of a prior art (conventional) coiled tubing fracturing tool:

Figure 2 is a side view of prior art equipment used in conventional coil fracturing operations;

Figure 3A is a schematic illustration of the penetration of fracturing or stimulation fluid between adjacent groups of perforations using prior art methods;

Figure 3B is a schematic illustration of a removable or breakaway cup arrangement according to the present invention;

Figure 3C is a side view illustration of the arrangement of movable or detachable cups for secondary containment;

Figure 4 is a schematic illustration of the use of a separate or removable cup for extended interval fracturing or stimulation according to the present invention;

Figure 5A is a partial cross-section of an embodiment of a movable cup assembly for attachment to a string of coils in accordance with the present invention;

Figure 5B is a side view of the movable cup of Figure 5A;

Figure 6A is a partial cross-section of a movable cup assembly according to the present invention;

Figure 6B is an exploded view of the movable cup assembly of Figure 6A;

Figure 7 is a side view of one embodiment of an apparatus for mounting a movable cup assembly according to the present invention;

Figure 8A is a perspective view of a separation cup design according to the present invention;

8B is an enlarged view of a cross-section of the engagement surface of the separation cup of FIG. 8A;

Figure 9A is a perspective view of a separation cup assembly according to the present invention;

Figure 9B is a cross-section of the assembly of Figure 9A; and

Figure 10 is a side view of an apparatus for installing a separation cup assembly according to the present invention.

Detailed ways

The invention in one embodiment is a method of fracturing or stimulating a subterranean formation using coiled tubing having an array of opposed pressure suppression devices. These devices may be frac cups or packer cups, expandable packer elements, or other such devices that will suppress the induced pressure between the pressure containment devices. The prior art of coiled tubing fracturing utilizes a set of opposing frac cups or packer cups secured to a bottomhole assembly that is attached to a string of coiled tubing. However, in the present invention, one or more upper pressure suppression devices are designed such that they can be strategically placed at locations on the coil to allow significantly larger intervals of fractures while still maintaining intact well operations.

The invention in another embodiment is a set of opposing frac cups for use in fracing a subterranean formation using coiled tubing. Contains additional upper cups or sets of upper cups that may be strategically placed at locations on the coil to allow a pressure barrier inside the sleeve to prevent contact with The pressure connection of the area.

The split cup design in one embodiment according to the invention can be used during fracturing or stimulation for extended fracturing or stimulation intervals or as secondary pressure suppression in the event of penetration behind the sleeve.

As with traditional methods, the coiled fracturing tool is connected to the coiled tubing and lubricated into the wellbore. If the purpose of the operation is extended fracturing or stimulation intervals, the coiled fracturing tool will be similar to a conventional coiled fracturing tool without being in a position that allows injection fluid to communicate with the wellbore above the top of the coiled fracturing tool One or more upper cups. If the purpose of the operation is secondary pressure suppression, then conventional coil frac tools will retain the upper cup as in conventional methods.

Adds a coil working window to the wellhead assembly between the coil BOP and the lubricator. The working window is a pressure integral device that opens and closes to allow access to the coil when the main valve is open and the coil is in the wellbore. Depending on the desired BOP configuration, avoid well pressure while the window is open by closing the coiled BOP's annular bag and/or tubing ram.

The desired configuration of a conventional coiled tubing fracturing tool (with or without one or more upper cups) is delivered into the wellbore in an as-is state to a point determined by the desired interval length of the fracture or as determined by the next set of adjacent perforations depth. After reaching this depth, the coil BOP (annular bag and/or tubing ram) is activated to suppress wellbore pressure, depressurize the lubricator system, and open the working window to access the coil.

In one embodiment of the invention, one or more sets of separation cups are attached to the coil and held by one or more sets of retaining or engaging members when the coil is exposed to the atmosphere in place. After securing the split cup assembly (which contains the cup and retaining member) to the coil, the working window is closed, the system pressure is tested, and the BOP is opened to allow the coil to be transported to the desired depth for fracturing operations.

After the fracturing operation is complete, the coil is pulled out of the wellbore, one or more upper cups are transported into the working window and removed following the reverse procedure of the procedure used to install the cups on the coil.

In another embodiment according to the invention, a solid one-piece upper pressure containment device, such as a frac cup or packer cup, is placed in a desired location on the coil string by positioning members on the BOP stack. The locating means may be a set of locator rams or C-plates or other similar means in windows to maintain the upper cup or cups stationary as the coiled tubing moves into the wellbore. The procedure will also require a working window to allow the upper cup(s) to be secured to the coil string so that the surface equipment will be the same as described above for the split cup embodiment.

Prior to attaching the coils to the fracturing tool carrying the bottom cup set or cups, an upper cup or set of cups with associated retaining members is placed over the coil string. After the top cup is placed on the coil, the frac tool is attached. The top cup is manually placed on the coil over a set of rams positioned just below or positioned in the working window by the plate and designed so that when the coil is transported into the well One or more top cups are held stationary.

The bottom cup or set of bottom cups is conveyed into the wellbore in the undisturbed state to a depth determined by the desired interval length of the fracture or by the interval between the targeted perforation and the next adjacent perforation. After reaching this depth, activate the coil BOP (annular bag and/or pipe ram) to suppress wellbore pressure, depressurize the lubricator system, and open the working window to access the coil and have been held by the locating ram or locating plate One or more top cups at the surface.

By exposing the coil to the atmosphere, one or more sets of retaining devices are secured to the coil such that the one or more cups are firmly held in place on the coil. This retaining member can be a solid mandrel device positioned on a coil with movable cups, a breakaway clamp that engages in a window, a helical retaining device that can be coiled onto a coil, or that holds one or more cups in place. Another such device in the location.

After the upper cup assembly (which contains the cup and retaining member) is secured to the coil, the working window is closed, the system pressure is tested, the BOP is opened, and the positioning gate is opened to allow the coil and upper cup assembly to be transported to the desired location. depth for fracturing operations.

After the fracturing or stimulation operation is complete, the coil is pulled out of the wellbore, the positioning rams are closed so that one or more upper cups are transported into the working window and the procedure used to install the cups on the coil is followed The reverse procedure to remove it.

It should be understood that in certain embodiments, the basis of the invention is the process of using an adjustable depth or movable pressure containment device which may be a fracture or A frac cup or other similar device that stimulates the spacer. There are several ways of introducing movable or adjustable depth cups on the coiled tubing into the wellbore. Several methods and apparatuses are described above, but the present invention is not intended to be limited to these methods and apparatuses and encompasses variations of both procedures and apparatuses.

In another embodiment, the present invention is directed to a method comprising injecting pressurized gas, liquid, solid proppant material, acid or solvent or a combination of these materials at high velocity and pressure to create, open and propagate fractures within a rock formation or to dissolve a rock formation Methods and systems within the materials. Use a coiled fracturing tool or similar device to suppress injection pressure and material on a given rock formation. The present invention provides strategic positioning of an upper cup or set of cups on the coil to enable extended length fracturing operations or strategic positioning of a second upper cup or set of cups on the plate in the event of secondary pressure suppression. way on the tube. It is not intended that the present invention be limited to the embodiments disclosed herein. Specifically, modifications to the process and apparatus may be made, which may include the use of specially coated or treated coils between the bottom and upper frac cups to protect the coils from wear, and include incorporating one or Alternative method for introducing multiple top cups into the coil.

Referring to FIG. 1 , a conventional coil fracturing tool consists essentially of a bottom cup or cup set 104 , an injection port 102 , an upper cup or cup set 103 and a coil connector 104 connecting the foregoing assembly to a coil 105 .

Referring to FIG. 2 , a conventional coiled tubing fracturing tool 201 is lubricated into a wellbore 202 by housing it in a lubricator 203 that is connected to a blowout preventer stack 204 . It should be clear that the interval length of the fracturing or stimulation is limited by the available height of the crane 205 used to suspend the coil injector 206 above the wellbore 202 .

Figure 3A shows the likelihood of fracturing or other stimulation causing penetration between adjacent sets of perforations. A conventional coiled tubing fracturing tool is shown in wellbore 301 having a bottom cup or cup set 302 and an upper cup or cup set 303 . Injection fluid 304 , which may include, but is not limited to, proppant-laden fracturing fluid, acid, or nitrogen, is introduced into the targeted perforation as shown in the region generally indicated by 305 . In some conditions, injection fluid 304 is allowed to migrate rearwardly of wellbore 301 to a set of upper perforations as shown in the region generally indicated by 306 , and reintroduced into wellbore 301 through the perforations at 306 . This may be due to poor cement bonding between the wellbore and the formation, or to vertical extension of fractures outside the wellbore 301 . Under conditions such as this, injected fluid 304 may then communicate with another set of upper perforations in the area generally indicated by 307 , causing unwanted fracturing or irritation of those upper perforations at 370 .

FIG. 3B shows the arrangement of movable or detached cups 308 on coiled tubing 309 that inhibit injection fluid 304 and prevent its communication with the upper set of perforations at 307 . This use of a removable or split cup system is referred to as "secondary containment" within this patent application.

Figure 3C enlarges the depiction of the arrangement of movable or split cups of secondary containment, which illustrates a conventional fracturing tool with a bottom cup 302, an upper cup 303, and a second upper cup 308 that is fixed to the disc. Removable or detachable cup for tube 309 .

Referring to Figure 4, it has been shown previously that a conventional coil fracturing tool may contain one or more sets of opposing cups to contain the injection pressure, and it has also been described that due to crane or lubricator limitations, when the upper cup is attached to the disc The spacing between these cups or sets of cups may be limited when the coil of tubing is integrated. Figure 4 depicts a split or removable cup application where the coil fracturing tool is modified such that it contains a bottom cup 401 but does not have an upper cup integral to the tool itself. The fracturing tool is connected to the coil 408 by the coil connector 402, but the upper cup is strategically positioned above the coil 408 above the coil connector 402 to provide extended interval separation or moveability for fracturing or stimulation Cup 403 , the extended spacing beyond what would be possible if the upper cup was integral to the coil fracturing tool and below the coil connector 402 . In this application, the injected fluid 404 is allowed to communicate and stimulate or fracture through perforations adjacent to the tool in the region generally depicted by 405 and vertically removed from the tool itself in the region generally depicted by 406 and 407 rock formations. This application is known as "extended length" fracturing or stimulation.

Figures 5A and 5B depict one embodiment of a removable cup. The movable cup has an enlarged inner diameter so that the coil can pass freely through the cup when transporting the coil in the well prior to attaching the cup to the coil. Typical packer cups for fracturing operations in 4.5 inch casings have an inner diameter of less than 2.625 inches, whereas these available cups have an ID (inside diameter) of 3.000 inches. Additionally, the cup is attached to its mounting mandrel by threads machined into the inner diameter of the upper portion of the outer ring 4 and screwed onto the slide holder. A conventional packer cup of the prior art is attached to a mandrel with a tapered support collar that clamps the rear of the cup against the mandrel.

The cup is sealed to the coil by an o-ring or alternative sealing technology. The conventional packer cups are sealed to their respective mounting mandrels by the interference fit created when the support rings of the conventional packer cups are tightened against the aft ends of the cups.

The cup also has a built-in breaking feature. If the cup becomes stuck in the well, there is a risk of the cup being pulled apart. The notched section on the threaded portion of the cup has been engineered to break upon application of a predetermined pull on the coil.

In Figure 5A, the assembled removable cup 501 is shown. The movable cup 501 comprises an outer collar 504 , an inner collar 505 and an elastic packer element 506 . The resilient element is typically hydrogen saturated nitrile rubber (HSN) or polyurethane, but may be any polymer deemed suitable for the downhole conditions the tool is expected to encounter.

Depending on the elastomer to be used, construction of the cup can be done in several ways. In one embodiment, the inner collar 505 is placed inside the outer collar 504 such that the bottom or shoulder of the inner collar 505 abuts outwardly against the inner diameter of the outer collar 504 . The inner collar 505 and outer collar 504 are then placed in a mold or casting that is preformed to provide the desired shape of the cup 506 . The elastomeric material is then poured or pressed into the mold and allowed to harden or cure and provide adhesion between the inner and outer collars and the elastomeric material.

Figure 5B is an exploded view of the components of Figure 5A to show additional detail. The surface of the inner collar 505 is ribbed to increase the adhesion between the elastomer and the inner collar 505, and again for the purpose of increasing the adhesion between the elastomeric material and the collar, the holes 507 may be Or may not be positioned in the outer collar 504 . A notch segment 503 is machined into the outer collar 504 to allow for a breaking point or weak point that would separate under a predetermined axial force if the assembly were sunk in the wellbore. Threads are added to the inner surface of the outer collar 504 in the area generally depicted by 502 so that it can be screwed onto the remainder of the assembly as described later in FIG. 6A .

An alternate embodiment would be to blast the surfaces of the inner collar 505 and outer collar 504 to provide a rough surface that would again improve the adhesion between the collar material and the elastomeric material.

The process of injection or compression molding is a common operation that requires no further explanation to those skilled in the art.

A second embodiment of this cup may be constructed with additional spring steel supports (not shown) for improved performance and structural support in severe applications. These spring steel supports may consist of concentric shells of sheet metal or fingers made of wire bent into a U shape. These spring steel supports are epoxied or welded or otherwise secured in the cavity between the outer collar 504 and the inner collar 505 . Other configurations of additional supports are contemplated and will be apparent to anyone skilled in the art of isolation cup construction.

Figure 6A depicts one embodiment of a removable cup system for selectively fracturing or stimulating extended intervals with coiled tubing as previously described with respect to the removable cup system.

The movable frac cup 501 is threaded onto the slider holder arrangement 605 and mounted to the coil 610 . The outer diameter and stiffness of the movable frac cup 501 is such that when transported into the sleeve and subjected to pressure from below the cup, the cup expands to form a seal against the inner diameter of the sleeve. Two o-ring arrangements 602 are inside the top of the movable cup 501 to form a seal between the inner surface of the movable cup 501 and the coil 610 . An o-ring spacer 603 is positioned between the two o-rings 602 to provide spacing and integrity between the o-rings 602 and the reduced ID sleeve 604 with which to eliminate any void space between the coil 610 and the slider holder 605 . The o-ring spacer 603 and reduced ID sleeve 604 must support the o-ring to prevent it from being squeezed onto the slider holder 605 . Although not explicitly shown in the figures, the o-ring spacer 603 and reduced ID sleeve 604 are each fabricated in two halves to allow for installation on pipe.

The slider holder 605 provides a means of positioning the number of sliders 606 between the slider holder 605 and the coil 610 . The sliders are in two layers within the slider holder 605 and essentially interact to prevent movement in either direction along the coil 601 . In the embodiment of FIG. 6A , the two layers of outer grapples 606 are separated and spaced by an intermediate slider support ring 607 . The upper layer of slider 606 is held in slider holder 605 by slider support ring 608 . A back nut 609 is used to hold the grapple 606 in place, and threading the back nut 609 into the slider holder 605 transmits axial force to the slider support ring 608 and the intermediate slider support ring 607 to initiate sliding Item 606.

Figure 6B is an exploded view of the assembly of Figure 6A (without the coil 610) to provide additional detail of the individual components.

Figure 7 shows the assembly of the apparatus for installation of the movable cup assembly. Working window 701 is used to allow access to coiled tubing 610 after it has been transported into the well. To those skilled in the art, working windows are common coil operating devices and need not be described in detail. Working window 701 is used to allow movable cup assembly 702 to be installed on coiled tubing 610 above bottomhole assembly 704 . The cup holder 703 is used in the working window 701 to hold the movable cup assembly 702 stationary in the working window 701 while the coil 610 is transported in the well. This cup holder 703 can be as simple as a C-shaped plate, which is well known to those skilled in the art of coil operation and will not be further described here.

The working window 701 is attached to a blowout preventer, generally indicated by the area depicted by 705, which houses one or more ram-type blowout preventers, one of which may be a pipe ram assembly 706 . The duct ram assembly is also a common device well known to those skilled in the art of coil operation and therefore will not be described in more detail.

For installation of the movable cup assembly, a socket connector (not shown) is attached to the end of the coiled tubing 610 to allow future installation of the bottom hole assembly 704 . Recessed connectors are also common devices to those skilled in the art and are therefore not further shown or described.

6A or 6B, to prepare the movable cup assembly as depicted at 702 in FIG. The middle slider support ring 607 is then slid onto the coil 610 as well.

Press the two o-rings 602 onto the threads of the slider holder 605 . The movable cup 501 is threaded onto the slider holder 605 to hold the o-ring 602 in place. Slider holder 605 with o-ring 602 and movable cup 501 are then slid onto coil 610 . Slider support ring 608 is dropped into slider holder 605 and support nut 609 is loosely threaded onto slider holder 605 to hold the assembly together.

If additional removable cups are to be installed, this process is repeated for each additional cup assembly.

Referring back to Figure 7, the bottom hole assembly 704 is connected to the coiled tubing using standard coiled tubing operating procedures.

The bottom hole assembly 704 and one or more movable cups 702 are then poked into the working window 701 . Cup retention member 703 is placed in working window 701 between bottom moveable cup assembly 702 and bottom hole assembly 704 . The working window 701 is closed, and the coiled tubing 610 is transported into the well to the desired depth while the cup holding member 703 holds the movable cup assembly 702 stationary in the working window 701 .

After the desired spacing between the movable cup assembly 702 and the bottom hole assembly 704 is reached, the coiled tubing 610 is stopped and the tubing ram 706 is closed to isolate the working window 701 from the wellbore. Working window 701 is opened to expose coiled tubing 610 and movable cup assembly 702 .

Referring again to FIG. 6A , the movable cup 501 is unscrewed from the slider holder 605 and the o-ring 602 is removed from the slider holder 605 and the coil 610 is allowed to be unconstrained. Slide the first o-ring 602 into the bottom of the packing gland of the slider holder 605 and push it to the bottom of the gland. Insert o-ring spacer half 603 into slider holder 605 and slide upper o-ring 602 down over o-ring spacer 603 .

Remove support nut 609 and slider support ring 608 from slider holder 605 . Place the reduced ID sleeve half 604 on the bottom of the slide holder 605 and screw the removable cup 501 onto the slide holder 605, which attaches the o-ring 602 and o-ring spacer 603 and The reduced ID sleeve 604 is locked in place.

The first layer of sliders 606 is mounted on top of the slider holder 605 and the slider support ring 607 is placed in the slider holder 605 on top of the first layer of sliders 606 . Each layer of slides can typically consist of three slides, but it can have more slides or it can have fewer slides. The second layer of sliders 606 is then inserted into the slider holder 605 on top of the middle slider support ring 607 and the slider support ring 608 is lowered down into the slider holder on top of the upper layer of sliders 606 . The back nut 609 is then threaded into the slider holder 605 and tightened so that the slider 606 is against the coil 610 .

Referring again to FIG. 7 , the cup retaining member 703 is then removed from the working window 701 and the working window 701 is closed, the tubing ram assembly 706 is opened, and the coiled tubing 610 is transported in the well to the desired depth for the stimulation procedure.

After the stimulation procedure is complete, the coiled tubing 610 is pulled out of the well to the depth of the mounting cup. The movable cup assembly 702 is pulled into the working window 701 , the conduit shutter 706 is closed, the working window 701 is opened, and the cup retaining member 703 is positioned in the working window 701 . The movable cup 501 is unscrewed from the slide holder 605 and the o-ring spacer 603 is removed, and the o-ring 602 is removed from the coil 610 . Back nut 609 is unscrewed and slide 606 is removed. The remaining assembly is then loosely screwed back together and allowed to drop onto the piping ram 706 inside the blowout preventer 705 .

The working window 701 is closed, the tubing shutter 706 is opened, and the coil 610 is pulled out of the well according to standard coil operating procedures.

A second method for achieving both applications of secondary pressure suppression and extended fracturing or stimulation length is now described. This embodiment uses a breakaway cup design that allows the pressure containment device or frac cup and retaining member to be mounted directly to the coil without the need to place the device on the coil while the coil is at the surface.

Referring to Figure 8A, there is shown a frac cup design that is split in half to allow placement of the cup on the coil after the coil has reached a certain depth in the wellbore. The cup is the same shape and size as cup 506 shown in FIG. 5B except that it is machined or molded into two separate halves 803 and 804 . Each half is shown with a male connection end 801 and a female connection end 802 such that when the two halves 803 and 804 are connected together by compressive force the two ends 801 and 802 fit together to form a pressure integral seal. FIG. 8B shows one example of a design for the mating surfaces, however, many different designs can be used to achieve the same functionality as shown by 801 and 802 .

Referring to FIG. 9A , the two cup halves 803 and 804 are shown engaged on the coil 901 , and the mating surfaces 801 and 802 are shown closed on the coil 901 . The two cup halves 803 and 804 are fixed in place on the coil 901 and the two packer cup mandrel halves 902 and 903 are locked in place by locking bolts 904 .

Figure 9B is a cross-section of the separation cup assembly shown in Figure 9A as described by section line A-A'. The packer cup mandrel halves 902 and 903 are shown secured to the coil 901 by a series of slides 905 constrained in position beneath the two cup mandrel halves 902 and 903 . The cups are additionally constrained by a series of interlocking grooves 906 that mate the exterior of the packer cups 803 and 804 with the cup mandrel halves 902 and 903 . An isolation chamber 907 is machined into the top of the packer cup and into both the packer cup mandrel halves 902 and 903 to allow insertion of a packer to create a gap between the coil 901 and the packer cup halves 803 and 804 provide pressure isolation between them. The packer cup mandrel halves 902 and 903 are locked in position on the coil 901 by one or more bolts 904 . To provide additional pressure support, the mating surfaces of cup halves 801 and 802 are offset 90 degrees from the mating surfaces of cup mandrel halves 902 and 903 .

Referring now to Figure 10, a coiled fracturing or stimulation tool 1001 is connected to coiled tubing 901 and lubricated into the wellbore according to conventional coiled tubing methods. A coiled fracturing or stimulation tool is configured with a bottom cup, and depending on the purpose of operation, the coiled fracturing or stimulation tool may or may not be configured with a top cup. The top cup is used when a split cup is desired for secondary pressure suppression and is not used if a split cup is desired for extended length fracturing or stimulation. The working window 1003 is connected to the top of the blowout preventer stack 1004 and the coiled fracturing tool 1001 is transported into the wellbore to a depth determined by the desired position of the breakaway cup. After reaching the desired depth, the coil 901 is stopped and the tubing ram 1005 is activated to isolate the working window 1003 from the wellbore pressure. The working window 1003 is pulled down and opened to allow access to the coil 901 . The separation cup halves 803 and 804 are attached to the coil 901, the isolation element (not shown) is placed in the isolation cavity (907 shown in FIG. 9B ) and the slide (shown in FIG. 9B 905) placed on the coil 901. The cup halves 803 and 804 and the slide 905 and packing element are locked by the packer cup mandrel halves 902 and 903 by locking bolts (904 as shown in FIGS. 9A and 9B ) to the proper position of the coil 901. in position. The working window 1003 is then closed, the tubing ram 1005 opened and the coiled tubing 901 transported into the well to the desired depth for fracturing or stimulation operations.

By marking the split cup assembly at the window or coil injector while pulling out the well, close the tubing shutter 1005, pull down the working window 1003, open the working window 1003 and remove by removing the bolt 904 and the remainder of the split cup assembly. Remove the separator cup assembly to complete the removal of the separator cup. The working window 1003 is then closed again, the pipe ram 1005 is opened and the coil fracturing or stimulation tool 1001 is pulled to the surface according to common coil operation.

It should be understood that the description of the installation and assembly of separate or removable cups may include one or more sets of separate or movable cups, depending on the degree of pressure suppression desired. Many modifications to assembly and installation procedures may be covered.

Claims (40)

1. the method for the pressure restraining in the pit shaft, it may further comprise the steps:

Coil pipe is provided;

Removable pressure containment devices is provided on described pipe;

Described pipe is inserted arrival first degree of depth in the described pit shaft, simultaneously described removable pressure containment devices is maintained the surface and pipe is passed described removable pressure containment devices;

Described removable pressure containment devices is fixed in the position on the described pipe; And

Described pipe is inserted arrival second degree of depth in the described pit shaft.

2. pressure restraining method according to claim 1, it further provides the bottom hole assemblies part, and wherein said first pressure containment devices is fixed to described bottom hole assemblies part.

3. pressure restraining method according to claim 2, wherein said bottom hole assemblies part comprise at least one the non-removable pressure containment devices that is fixed on the described bottom hole assemblies part.

4. according to claim 2 or 3 described pressure restraining methods, wherein said bottom hole assemblies part is a fracturing tool.

5. according to the described pressure restraining method of arbitrary claim in the claim 1 to 4, wherein said removable pressure containment devices comprises locking component, and described locking component is used for described removable pressure containment devices is fixed on the described pipe so that disapprove described pipe when described pit shaft arrives described second degree of depth and pass described pressure containment devices when described pipe is inserted.

6. according to the described pressure restraining method of arbitrary claim in the claim 1 to 5, it further comprises along the following of described removable pressure containment devices and fluid is incorporated into step in the described pit shaft to eyelet, and described whereby pressure containment devices limits the circulation of described fluid along the upward hole eye of described removable pressure containment devices.

7. according to the described method of arbitrary claim in the claim 3 to 6, wherein said non-removable pressure containment devices is a packer cup.

8. according to the described pressure restraining method of arbitrary claim in the claim 1 to 7, wherein said pressure restraining is that first class pressure suppresses.

9. according to the described pressure restraining method of arbitrary claim in the claim 1 to 7, wherein said pressure restraining is that secondary pressure suppresses.

10. according to the described pressure restraining method of arbitrary claim in the claim 1 to 7, wherein said pressure restraining is that three stage pressures suppress.

11. the method for the pressure restraining in the pit shaft, it may further comprise the steps:

Coil pipe is provided;

Described coil pipe is transported to arrival first degree of depth in the pit shaft;

Pressure containment devices is attached on the described pipe in the surface; And

Described coil pipe is transported to arrival second degree of depth in the described pit shaft.

12. pressure restraining method according to claim 11, it further provides the bottom hole assemblies that is connected to described pipe part.

13. pressure restraining method according to claim 12, wherein said bottom hole assemblies part comprise at least one non-removable pressure containment devices.

14. according to the described pressure restraining method of arbitrary claim in the claim 11 to 13, wherein said pressure containment devices is a separate cup.

15. according to the described pressure restraining method of arbitrary claim in the claim 12 to 14, wherein said bottom hole assemblies part is a fracturing tool.

16. according to the described pressure restraining method of arbitrary claim in the claim 11 to 15, wherein said pressure containment devices further comprises and is used for described pressure containment devices is fixed on locking component on the described pipe.

17. according to the described pressure restraining method of arbitrary claim in the claim 11 to 16, it further comprises along the following of described pressure containment devices and fluid is incorporated into step in the described pit shaft to eyelet, and described whereby pressure containment devices limits the circulation of described fluid along the upward hole eye of described pressure containment devices cup.

18. the method for the pressure restraining in the pit shaft, it may further comprise the steps:

Coil pipe is provided, has first fixation pressure on the described pipe and suppress cup;

Removable pressure restraining cup is provided on described pipe;

Described pipe is transported to arrival first degree of depth in the described pit shaft, simultaneously described removable pressure restraining cup is maintained the surface and pipe is passed described removable pressure cup;

In described removable glass of position that is fixed on the described pipe; And

Described pipe is transported to arrival second degree of depth in the described pit shaft.

19. pressure restraining method according to claim 18, it further provides the bottom hole assemblies part, and the wherein said first pressure restraining cup is fixed to described bottom hole assemblies part.

20. pressure restraining method according to claim 19, wherein said bottom hole assemblies part is a fracturing tool.

21. according to the described pressure restraining method of arbitrary claim in the claim 18 to 20, wherein said removable cup further comprises locking component, and described locking component is used for described removable cup is fixed on the described pipe so that disapprove pipe when described pit shaft arrives described second degree of depth and pass described removable glass when described pipe is transported to.

22. according to the described pressure restraining method of arbitrary claim in the claim 18 to 21, it further comprises along the following of described removable cup and fluid is incorporated into step in the described pit shaft to eyelet, and the described fluid of described whereby removable cup restriction is along the circulation of the upward hole eye of described removable cup.

23. the method for the pressure restraining in the pit shaft, it may further comprise the steps:

Coil pipe is provided, has first fixation pressure on the described pipe and suppress cup;

Described pipe is transported to arrival first degree of depth in the described pit shaft;

The pressure restraining member is provided and is fixed in the position of end of the non-described pipe on the described pipe; And

Described pipe is transported to arrival second degree of depth in the described pit shaft.

24. pressure restraining method according to claim 23, it further provides the bottom hole assemblies part, and the wherein said first pressure restraining cup is fixed to described bottom hole assemblies part.

25. pressure restraining method according to claim 24, wherein said bottom hole assemblies part is a fracturing tool.

26. according to the described pressure restraining method of arbitrary claim in the claim 23 to 25, it further comprises along the following of described pressure restraining member and fluid is incorporated into step in the described pit shaft to eyelet, and described whereby pressure restraining member limits the circulation of described fluid along the upward hole eye of described pressure restraining member.

27. according to the described pressure restraining method of arbitrary claim in the claim 18 to 26, it further comprises along the following of described pressure restraining member and suppresses cup to second fixation pressure of eyelet on described pipe.

28. pressure restraining method according to claim 27, wherein said second fixation pressure suppress cup and are fixed to described bottom hole assemblies part along the following of described pressure restraining member to eyelet.

29. one kind is used for fluid restraining device fluid-encapsulated in pit shaft, it comprises: sleeve pipe, and it is used to be placed on coil pipe; And releasable locking component, it is used for described device is locked in described coil pipe, whereby when described locking component is in non-locked position, can make coil pipe pass described device.

30. pressure containment devices according to claim 29, wherein said device is a packer cup.

31. pressure containment devices according to claim 29, wherein said device is a fracture cups.

32. a coil pipe composite member, it comprises coil pipe and the removable pressure restraining member on described coil pipe.

33. coil pipe composite member according to claim 32, it comprises along the following of described removable inhibition member and suppresses cup to first fixation pressure of eyelet on described pipe.

34. coil pipe composite member according to claim 33, it further comprises the bottom hole assemblies part, and wherein said first fixation pressure inhibition cup is fixed to described bottom hole assemblies part.

35. coil pipe composite member according to claim 34, wherein said bottom hole assemblies part is a fracturing tool.

36. according to the described coil pipe composite member of arbitrary claim in the claim 33 to 35, wherein said removable inhibition member further comprises locking component, and described locking component is used for described removable inhibition member is fixed on the described pipe so that can make pipe pass described removable cup.

37. according to the described coil pipe composite member of arbitrary claim in the claim 33 to 36, it further comprises along the following of described removable inhibition member and suppresses cup to second fixation pressure of eyelet on described pipe.

38. a fluid that is used for suppression fluid in pit shaft suppresses cup, it comprises two sleeve halves.

39. suppress cup according to the described fluid of claim 38, it comprises and is used for described half one is locked together releasedly to form the locking component of sleeve pipe.

40. suppress cup according to the described fluid of claim 39, wherein said locking component comprises positive connecting elements and cloudy connecting elements.

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