WO2013037055A1

WO2013037055A1 - Wellbore frac tool with inflow control

Info

Publication number: WO2013037055A1
Application number: PCT/CA2012/050612
Authority: WO
Inventors: Robert Joe Coon
Original assignee: Packers Plus Energy Services Inc
Current assignee: Packers Plus Energy Services Inc
Priority date: 2011-09-12
Filing date: 2012-09-05
Publication date: 2013-03-21
Anticipated expiration: 2014-03-12
Also published as: BR112014005570A2; EP2756163A4; AU2012308069A1; US20140224471A1; CA2847972A1; EP2756163A1

Abstract

An apparatus for fluid treatment of a borehole includes: a tubular body having a long axis and an upper end, a first port extending through the wall of the tubular body, a second port extending through the wall of the tubular body, the second port having a fluid inflow control mechanism positioned to control the flow of fluid into the tubular body through the port, the first port being configurable from an open position to a closed position; and a controller to actuate the first port into the closed position, a set time after the first port is placed into the open position.

Description

WELLBORE FRAC TOOL WITH INFLOW CONTROL

RELATED APPLICATIONS

This application claims priority to US 61/533,660, filed September 12, 201 1. FIELD

The invention relates to a method and apparatus for wellbore fluid treatment and, in particular, to a method and apparatus for selective communication to a wellbore for fluid treatment and effectively handling produced fluids.

BACKGROUND

An oil or gas well relies on inflow of petroleum products. When natural inflow from the well is not economical, the well may require wellbore treatment termed stimulation. This is accomplished by pumping stimulation fluids such as fracturing fluids, acid, cleaning chemicals and/or proppant laden fluids to improve wellbore inflow.

In one previous method, 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, the stimulation fluids are sometimes allowed to back flow from the formation into the wellbore tubing string. Thereafter, fluids are produced from the formation. In some embodiments, the produced fluids also enter the tubing string for flow to the surface. Such wellbore treatment systems are described in US Patents 7,748,460 and 7,543,634 and PCT application PCT/CA2009/000599, to Packers Plus Energy Services Inc.

It may be advantageous in certain circumstances to control the inflow of produced fluids. For example, it may be advantageous to screen the produced fluids before they enter the tubing string. In addition or alternately, the produced fluids may require flow rate control, as by use of chokes including devices called inflow control devices (ICD).

SUMMARY

In accordance with a broad aspect of the present invention, there is provided an apparatus for fluid treatment of a borehole, the apparatus comprising: a tubular body having a long axis and an upper end, a first port extending through the wall of the tubular body, a second port extending through the wall of the tubular body, the second port having a fluid inflow control mechanism positioned to control the flow of fluid into the tubular body through the port, the first port being configurable from an open position to a closed position; and a controller to actuate the first port into the closed position, a set time after the first port is placed into the open position.

There is also provided a method for fluid treatment of a borehole, the method comprising: running a tubing string into a wellbore to a desired position for treating the wellbore; opening an outflow port by application of a force to a sliding sleeve valve for the port; injecting stimulating fluids through the outflow port; closing the outflow port after a selected time; opening the fluid inflow control port automatically; and permitting fluid to pass from the wellbore into the tool through the fluid inflow control port.

It is to be understood that other aspects of the present invention will become readily apparent to those skilled in the art from the following detailed description, wherein various embodiments of the invention are shown and described by way of illustration. As will be realized, the invention is capable for other and different embodiments and its several details are capable of modification in various other respects, all without departing from the spirit and scope of the present invention. Accordingly the drawings and detailed description are to be regarded as illustrative in nature and not as restrictive. BRIEF DESCRIPTION OF THE DRAWINGS

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

Figure 1 is an axial sectional view through a wall of a well treatment tubular in a run in condition;

Figure 2A is a view of the well treatment tubular of Figure 1 in a position in a wellbore and opened for annular fluid treatment through the tubular;

Figure 2B is a enlarged section through the check valve of Figure 2A;

Figure 3 is a view of the well treatment tubular of Figure 1 in a position closed after the annular fluid treatment through the tubular;

Figure 4A is a view of the well treatment tubular of Figure 1 in a position with inflow occurring through the inflow port;

Figure 4B is an enlarged section through the check valve of Figure 4A;

Figure 5 is an enlarged section through the check valve after being eroded by inflow;

Figure 6 is a view of the well treatment tubular of Figure 1 in a position with the inflow port being closed;

Figure 7 is a view of the well treatment tubular of Figure 1 being treated to remove the ball seats; and Figure 8 is a view of the well treatment tubular of Figure 1 with a full open bore. DETAILED DESCRIPTION

The description that follows, and the embodiments described therein, is provided by way of illustration of an example, or examples, of particular embodiments of the principles of various aspects of the present invention. These examples are provided for the purposes of explanation, and not of limitation, of those principles and of the invention in its various aspects. The drawings are not necessarily to scale and in some instances proportions may have been exaggerated in order more clearly to depict certain features. Throughout the drawings, from time to time, the same number is used to reference similar, but not necessarily identical, parts.

A method and apparatus has been invented which provides for injecting of a wellbore treatment fluid and then reconfiguration to control the flow of produced fluids. The apparatus and methods of the present invention can be used in various borehole conditions including open holes, cased holes, vertical holes, horizontal holes, straight holes or deviated holes.

With reference to the drawings, the apparatus is a wellbore treatment tubular with tubular body 10 having a long axis x extending from its upper end 10a to its lower end 10b. An inner bore 12 is defined within the inner surface 10c of the tubular body's wall. An outlet port 14 extends through the wall providing fluid communication between inner bore 12 and an outer surface lOd of the wall. A sliding sleeve 16 is positioned in the wellbore treatment tubular to control the open and closed condition of outlet port 14. In this embodiment, sliding sleeve 16 is positioned in inner bore 12 and is moveable between a position overlying, and therefore closing, port 14 (Figure 1) and a position retracted from, and therefore opening, port 14 (Figure 2). Sliding sleeve 16 can move between the closed position and the open position by application of a force to move the sleeve. In this illustrated embodiment, force to move the sleeve is hydraulic. In this illustrated embodiment, sliding sleeve 16 includes a ball seat 18 on which a plug such as a ball 19 can be landed to create a seal and to allow a hydraulic force to be developed to push the sleeve along the inner bore. Sleeve 16 is normally held in a port closing position by a holding mechanism 20, such as a shear pin, but can be moved if sufficient force is applied to overcome the holding force of mechanism 20. A reclosing sleeve 22 is also provided to reclose port 14. While reclosing of port 14 could be effected through a portion of sleeve 16 (i.e. further movement of sleeve 16 to again overlie port 14), in this embodiment reclosing sleeve 22 is a separate component from sleeve 16. Reclosing sleeve 22 is positioned in the wellbore treatment tubular inner bore 12 and is moveable between a position retracted from port 14 (Figures 1 and 2) and a position overlying, and therefore reclosing, port 14 (Figures 3 to 8). Sleeve 22 can move between the retracted position and the reclosing position by application of a force to move the sleeve. In this illustrated embodiment, hydraulic pressure is employed to apply the force. Seals 29, 29a, 29b ensure that pressure is harnessed to drive sleeve 22 and also prevent leakage through port 14.

In particular, in the illustrated apparatus, hydraulic pressure to move sleeve 22 is from a hydraulic chamber 23a placeable in communication with fluid external to the tool, called hydrostatic fluid in the well. Sleeve 22 only moves to reclose port 14 after a selected time lapses, that selected time being counted from when port 14 is first opened.

In the illustrated embodiment, a sensor senses the movement of sleeve 16 to open port 14 and the movement triggers a timer to count down to opening chamber 23a to hydrostatic pressure, which acts against an isolated pressure, for example lower, atmospheric pressure, chamber 23b to close sleeve 22. The sensor may include, for example, a magnetic proximity switch such as may include a hall effect sensor 24 and a magnet 25, one of which is carried on the sleeve and the other of which is installed on the tubular body. Hall effect sensor 24 may be in communication with a processor such as circuit board 26. Circuit board 26 and its power source 26a may be installed in a protected chamber. Circuit board 26 may have a timer integrated therein that delays opening of sleeve 22 until after a selected time has lapsed after movement of sleeve 16 is sensed by the sensor.

Sleeve 22 may be moved by flooding chamber 23a with hydrostatic pressure against an atmospheric chamber 23b. For example, a "hole opener" can be employed, which includes a small plug 27 held in a plugging position in an fluid supply inlet 28 to chamber 23. Plug 27 is held in place by a holder, such as a high strength filament, such as for example, a Kevlar™ string. In this embodiment, the high strength filament that holds plug 27 in place may be destroyed by burning, for example, by powering a coil about the filament when it is desired to destroy the filament. For example, the "hole opener" can be actuated by sending a current through a conductor to the holder to release the plug from its plugging position. The current through the conductor burns the Kevlar string releasing plug 27 and allowing the chamber 23 a to flood with hydrostatic pressure from outer surface lOd. While chamber 23a was previously at a pressure similar to that of chamber 23b, once chamber 23a is flooded, the greater pressure of chamber 23a moves sleeve 22 to cover port 14. It is noted that seal 29a has a greater area than seal 29b and thus the flooding of chamber 23a creates a force against seal 29a greater than the force against seal 29b and this moves sleeve 22 to close port 14.

Sleeve 22 is normally held in the retracted position by a holding mechanism 30, such as a shear pin, but can be moved if sufficient force is applied to overcome the holding force of mechanism 30.

In the same segment of tubular body, or connected directly or indirectly thereto as shown, is a fluid inflow control mechanism including at least one inflow port 38 and an inflow controller 40 for that port. While inflow port 38 and fluid treatment port 14 are shown positioned on separate components and axially spaced, they may be otherwise configured but do provide for fluid outflow from inner bore and fluid inflow to inner bore from the same annular space. In some embodiments, tubular body 10 may carry packers 41 that are settable to isolate the segment of the well accessed by ports 14, 38 from other segments of the well.

Inflow controller 40 controls in some way the inwardly directed flow of fluids, which are those passing from outer surface lOd to inner bore 12. In this embodiment, inflow controller 40 includes a screen 42 and a choking orifice 44, better known as an Inflow Control Device (ICD), although controller may include one or the other or other inflow controlling components such as a labyrinth channel. In one embodiment, the inflow controller is adjustable and in one embodiment remotely adjustable, such as while the apparatus is positioned downhole. The port may include a restriction, as shown, if it is to function as an ICD. Alternately, the port may be fully open if it's only inflow control function is as a sand screen. Port 38 is controlled to open automatically when fluid pressure on the outer surface is greater than pressure in inner bore 12. For example, port 38 is normally closed but opens when production pressure builds up in the annulus 72. The pressure differential may be controlled by controlling tubing pressure and pressure in the annulus can build up when port 14 is closed. In one embodiment, for example, port 38 may have a check valve 46 installed therein that only allows fluid to enter the tubing but restricts fluid from traveling from the tubing inner bore 12 outwardly toward outer surface lOd. Port 38 is exposed in the inner bore 12, but check valve 46 prevents fluid from passing therethrough outwardly. For example, check valve 46 and/or port 38 may carry seals that are forced together to seal flow through the ports. Alternately or in addition, port 38 may be formed with an inner diameter that tapers outwardly, for example frustoconically, and check valve 46 may be similarly frustoconically formed, for example, with a poppet 48 that is conically formed, tapering toward its outer end. When the pressure differential between the ends of the poppet is greater in the im er bore than that pressure at outer surface lOd, poppet 48 is forced against the tapering surface defining port 38.

Check valve 46 may have a temporary installation, as shown, such that it eventually is rendered in operative, such that eventually the check valve doesn't have any effect in port 38 and port 38 may be substantially fully open. For example, check valve 46 may be erodable, including for example poppet 48 or a support for the poppet. In the illustrated embodiment, poppet 48 is held in place by an erodable plate 50 and a biasing spring 52. When erodable plate 50 is in place, poppet 48 and spring 52 operate according to a flow checking mode in port 38. However, when erodable plate 50 sufficiently erodes away, the poppet and the spring can fall out of port 38, leaving it unrestricted. Erodable plate 50 may have one or more openings therethrough to allow some flow of fluids therethrough, but that flow erodes by the erosive particulate content and/or force of the flow of the fluids. Plate 50 may be formed of materials able to withstand immersion in wellbore fluids but erodible after a period of time downhole or after a period of time with flow therethrough. Plate 50 may be formed of materials softer than steel such as mild steel, aluminum, plastic, etc. A channel 54 is formed through inflow control mechanism 40 through which fluid can pass from screen 42 to orifice 44 to port 38.

The inflow control mechanism may include a closing sleeve 56 to close port 38. While closing of port 38 could be achieved by a portion of sleeve 16 or sleeve 22 (i.e. further movement of one of these sleeves to overlie port 38), in this embodiment closing sleeve 56 is a separate component from the other two sleeves, Closing sleeve 56 for inflow port 38 is positioned in the wellbore treatment tubular inner bore 12 and is moveable between a position retracted from port 38 (Figures 1 to 4) and a position overlying, and therefore reclosing, port 38 (Figures 6 to 8). Sleeve 56 can move between the retracted position and the reclosing position by application of a force to move the sleeve. In this illustrated embodiment, a tool, such as a shifting tool 60, is employed to apply the force. Shifting tool 60 engages sleeve 56, for example, through a landing profile 62, and can move the sleeve axially to overlie and cover port 38. Seals 64 may be provided to prevent leaks between body 10 and sleeve 56. A releasable lock, such as a snap ring 66 landable in glands 68a, 68b, may be provided to ensure that the sleeve is resistant to accidental migration, but is moveable when gripped and moved.

In use, tubular body 10 may be connected into a string and run into a wellbore, defined by wall 70. An annulus 72 is formed between wall 70 and outer surface lOd. Packers 41 may be set to create an isolated segment of the annulus to which both ports 14 and 38 communicate.

To fluid treat the wellbore, sleeve 16 is opened by dropping a ball 19 to land on seat 18. Ball 19 and seat 18 act as a piston and pressure can be increased uphole thereof to create a differential to drive the seat and the ball, and thereby sleeve 16 down. Port 14 is opened by movement of sleeve 16 and a fluid treatment, arrows F, can be undertaken through port 14. Fluid treatment can include wellbore stimulation, such as fracturing. Port 14, being open, provides for substantially unrestricted passage of the fluid treatment to the wellbore.

This movement of sleeve 16 is sensed at the processor, since magnet 25 moves away from hall sensor 24. A timed count down is then initiated by the timer. The countdown time can be set when the tool is being prepared at surface and is a time suitable to allow the fluid treatment to be completed and, if desired, any initial back flow.

Port 14 closes once the timer runs out. For example, once the time set by the timer has lapsed, a port closure release mechanism operates. For example, the "hole opener" can be actuated to allow fluid to drive reclosing sleeve 22 to close over port 14. In the embodiment, employing plug 27 and a Kevlar string as the hole opener, circuit board 26 may send a current through a wire to the coil around the Kevlar string. The current burns the Kevlar string releasing the plug 27 from inlet 28 and allowing chamber 23a to flood with hydrostatic pressure from annulus 72. This moves sleeve 22 to close port 14. Thus a delay closing mechanism is provided for fracturing port 14, wherein port 14 can be opened, but will be automatically closed after a certain, set time has lapsed.

Once fracturing port 14 closes, port 38 will eventually open automatically when the pressure of fluids outside the tubular overcomes check valve 46. Once opened, the inflow of produced fluids, arrows P, is controlled. In this embodiment, the well is produced through filter 42 and all proppant may remain in place after the frac. Screen 42 filters the fluid and keeps the sand particles out of tubing 10. It is beneficial after the frac to keep the proppant in place, such that it is not produced back to the surface. After passing through filter 42, the filtered fluid then passes into the tubular inner diameter through channel 54, orifice 44 and port 38.

Check valve 46 allows the stimulation of the stage between packers 41 through fracturing port 14 without that fluid passing outwardly through inflow control port 38, such that the inflow controller 40 (i.e. screen 42/orifice 44) are not damaged from fluids F injected out from inner bore 12. Once the stimulation is complete, fracturing port 14 is closed, and the well is allowed to produce. After production is initiated, check valve 46 opens and the fluid enters the tubing 10. The produced fluid P has most of the sand and debris filtered out, but the small amount that is left and the velocity of the fluid erodes out check valve 46 and eventually an unrestricted path is created through port 38 for the fluid to enter the tubing string. Figure 1 shows the tubular apparatus, including inflow controller (i.e. screen 42 and ICD 44) and port 38 and fracturing port 14 and the delay mechanism, in the run in condition.

A tubular string segment shown in the drawings includes inflow controller 40 connected above fracturing port 14. The inflow controller doesn't need to be threaded directly to the tube containing the fracturing port; it could be several 100 feet away as long as the inflow port and the fracturing port are in fluid communication along the outside of the tubular. This generally means that the inflow port and the fracturing port are in the same interval in the installed string, for example, between the same pair of packers 41 in a packer isolated wellbore.

In Figures 2, a launched ball 19 has just hit ball seat 18 and fracturing port 14 is opened with the fluid treatment exiting the port to stimulate the formation. The proximity sensor senses the movement of sleeve 16 and starts the timer. In this embodiment, for example, circuit 26, through hall sensor 24, senses that the magnet, and thereby sleeve 16, has moved away and starts the countdown as set in timer. The fluids of the fluid treatment, including proppant, don't enter the sand screen through port 38 since the check valve is held in place with the pressure from the frac. A pressure differential develops between the ends of poppet 48, wherein the pressure in the inner bore is greater than the pressure at outer surface lOd and poppet 48 is forced against the tapering surface defining port 38.

In Figure 3, the predetermined time has run out on the timer and the holder has been released. The hydrostatic pressure has pushed sleeve 22 down closing fracturing port 14. In this illustrated embodiment, according to the timer the circuit board has sensed that the time has lapsed and has completed the circuit to burn the Kevlar and to release plug 27 from its plugging position in inlet 28. Once the holder for the plug is removed, hydrostatic pressure pushes the plug through inlet 28 into chamber 23a and the chamber floods with fluid and sleeve 22 is driven to close.

With port 14 closed, the pressure of the produced fluids can build up, as shown in Figures 4 A and 4B, and eventually, check valve 46 opens and inflow, arrows P, proceeds through filter 42 and orifice 44. The inflow, arrows P, erodes the check valve until port 38 is fully open (Figure 5), allowing the flow only to be restricted by the orifice. For example, as shown in Figures 4B and 5, after a short amount of time, erodable plate 50, which retains poppet 48 in port 38, erodes away and the poppet and spring 52 fall out of the port.

If the stage starts to produce too much water and, thus, makes this interval uneconomic or if it otherwise of interest to close off production through that interval, port 38 can be closed by closing sleeve 56 moved by a shifting tool 60 (Figure 6). Shifting tool may be a standard B shifting tool, as shown, or another type of shifting tool. The sleeve may be gripped by use of gland 62.

As shown in Figure 7, if desired the operator can introduce a mill 80 and mill out seat 18 on the fracturing port sleeve 16 with ports 14, 38 open or closed. In Figure 8, apparatus is shown with the ball seat milled out and ports 14 and 38 closed. Port 38 could be reopened by moving sleeve 56 with a shifting tool to resume production, if desired. Sleeve 56 may be formed recessed at least in part out of the diameter to be milled such that it retains its gland 62 and can be positively gripped for movement.

The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments without departing from the spirit or scope of the invention. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article "a" or "an" is not intended to mean "one and only one" unless specifically so stated, but rather "one or more". All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are know or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims. No claim element is to be construed under the provisions of 35 USC 112, sixth paragraph, unless the element is expressly recited using the phrase "means for" or "step for".

Claims

Claims:

1. An apparatus for fluid treatment of a borehole, the apparatus comprising:

a. a tubular body having a long axis and an upper end;

b. a first port extending through the wall of the tubular body;

c. a second port extending through the wall of the tubular body, the second port having a fluid inflow control mechanism positioned to control the flow of fluid into the tubular body through the port;

d. the first port being configurable from an open position to a closed position; and e. a controller to actuate the first port into the closed position, a set time after the first port is placed into the open position.

2. The apparatus of claim 1 further comprising a first closure positioned relative to the first port, moveable from a position closing the first port to a second position placing the first port in the open position and a second closure positioned relative to the first port, moveable from a position away from the first port to a position overlying the first port and placing the first port in the closed position and the controller actuates the second closure to move to the position overlying the first port after the set time.

3. The apparatus of claim 2 wherein the controller includes a sensor to sense when the first closure moves into the second position.

4. The apparatus of claim 1 wherein the controller includes a circuit including a timer.

5. The apparatus of claim 2 wherein the second closure is driven by hydrostatic pressure.

6. The apparatus of claim 1 wherein the second port is normally closed and openable automatically when pressure external to the tubular body is greater than pressure internal to the tubular body.

7. The apparatus of claim 1 wherein the second port resists flow outwardly therethrough from the tubular body.

8. The apparatus of claim 1 further comprising a check valve in the second port, the check valve resisting flow outwardly through the second port from the tubular body and being openable automatically when pressure external to the tubular body is greater than pressure internal to the tubular body.

9. The apparatus of claim 8 wherein the check valve is temporary.

10. The apparatus of claim 8 wherein the check valve is erodable.

1 1. A method for fluid treatment of a wellbore, the method comprising:

a. running a tubing string into a wellbore to a desired position for treating the wellbore;

b. opening an outflow port by application of a force to a sliding sleeve valve for the port;

c. injecting stimulating fluids through the outflow port;

d. closing the outflow port after a selected time;

e. opening the fluid inflow control port automatically; and

f. permitting fluid to pass from the wellbore into the tool through the fluid inflow control port.

12. The method of claim 1 1 wherein closing the outflow port occurs after a selected time from the opening of the outflow port.

13. The method of claim 1 1 wherein closing the outflow port includes automatically opening a closing sleeve to hydrostatic pressure to drive the closing sleeve over the outflow port.

14. The method of claim 11 wherein opening the fluid inflow control port occurs automatically when a pressure differential is established wherein pressure external to the tubular body is greater than pressure internal to the tubular body.

15. The method of claim 14 wherein the pressure differential is established by closing the outflow port.

16. The method of claim 1 1 wherein permitting fluid to pass includes screening the fluid.

17. The method of claim 1 1 wherein permitting fluid to pass includes controlling the pressure of the fluid passing through the fluid inflow control port.