US20170081940A1

US20170081940A1 - Wellbore packer, method and tubing string

Info

Publication number: US20170081940A1
Application number: US15/103,738
Authority: US
Inventors: Daniel Jon Themig
Original assignee: Cypress Semiconductor Corp
Current assignee: Cypress Semiconductor Corp
Priority date: 2013-12-11
Filing date: 2014-12-11
Publication date: 2017-03-23
Also published as: WO2015085427A1; CA2933463A1

Abstract

A wellbore packer for setting one or more packing elements in a borehole having an open hole section. The wellbore packer comprises a port-less mandrel configured with one or more packing elements and one or more setting mechanisms. The setting mechanism is responsive to a driving force and configured to set the packing elements in the borehole, wherein the driving force is not tubing string pressure. Where packers are set by annular pressure, a method for setting a plurality of such packers may include sequentially operating the packers. A mechanism may be provided for the packers to allow sequential operation thereof.

Description

FIELD OF THE INVENTION

The invention relates to a tool, method and string for wellbore operations and, in particular, a packer, a tubing string and a packer-setting method for a wellbore.

BACKGROUND OF THE INVENTION

In wellbore operations, packers may be used to control migration of fluids outside a tubing string such as a liner or other casing installed in the wellbore. For example, packers may be installed in the annulus between the tubing string and the wellbore wall to deter migration of the fluids axially along the annulus.
Packers may be actuated and/or set by application of hydraulic pressure. Oftentimes, the hydraulic pressure is introduced through the tubular string on which the packer is installed and is communicated to the packer's hydraulically actuated system by a port through the tubular wall, also called a mandrel, on which the packing elements are installed. The port extends through the tubular wall and provides communication from the tubing string inner diameter and the hydraulic cylinder for the packer. There are seals within the cylinder that contains the hydraulic pressure so that the pressure biases the cylinder to set the packer.
One of the disadvantages of hydraulically set mechanical packers is the port in the tubular wall. In pressuring applications, for example, when fracing a well and/or pressurizing the liner, the hydraulic cylinders are subjected to the pressures being utilized and in some cases, empty cyclic pressures, which results in cylinders moving and seals moving under pressure situations, which can be greater than 10,000 psi and at elevated temperatures. Under such conditions, the ports in the tubing string that open to the packer setting chambers introduce a point of weakness and potential failure. Additionally, in high temperature applications, seals, and the like, can degrade, and a leak path can form through the port in the mandrel and into the annulus, past the problematic seals.
Accordingly, there remains a need for improvements in the art.

BRIEF SUMMARY OF THE INVENTION

In accordance with a broad aspect of the present invention, there is provided a wellbore packer with a port-less mandrel.
In accordance with another broad aspect, there is provided a method for installing a packer to create a seal in a wellbore defined by a wellbore wall, the method comprising: running the packer into a wellbore, the packer installed along a tubing string and including a packing element and a setting mechanism for the packing element; positioning the packer in the wellbore adjacent an open hole section of the wellbore wall to create an annular area between the packer and the wellbore wall; setting the packer while isolating tubing string pressure from the packer setting mechanism and while maintaining hydrostatic pressure in the annular area; and allowing the packing element to expand to create a seal in the annular area between the tubing string and the open hole section of the wellbore wall.
According to another embodiment there is provided a wellbore installation in a wellbore comprising: a tubing string including a frac port; a wellbore packer connected into the tubing string and forming an annular seal in the wellbore separating a first annular area accessed through the frac port from a second annular area, the wellbore packer including: a port-less mandrel having a longitudinal axis; a packing element coupled to said mandrel; a setting mechanism coupled to said port-less mandrel including a piston configured with a compressing ring proximate one end of the packing element, and a stop ring proximate another end of said packing element, said stop ring being affixed to said mandrel and configured to block movement of said packing element; the setting mechanism configured to be responsive to a driving force to drive the piston in a first direction along said longitudinal axis to move said compressing ring against said one end of said packing element and compress said packing element against said stop ring so that said packing element is compressed and expands outwardly from said port-less mandrel to form the seal in the wellbore; and a port for communicating fluid from the first annular area to the piston.
According to another embodiment, there is provided a wellbore packer for creating a seal in a borehole, said wellbore packer comprising: a port-less mandrel having a longitudinal axis; first and second packing elements coupled to said mandrel in a spaced relationship along said longitudinal axis; a first piston configured with a first compressing ring proximate one end of said first packing element, and a first stop ring proximate another end of said first packing element, said first stop ring being affixed to said mandrel and configured to block movement of said first packing element; a second piston configured with a second compressing ring proximate one end of said second element, and a second stop ring proximate another end of said second packing element, said second stop ring being affixed to said mandrel and configured to block movement of said second packing element; a drive mechanism coupled to said port-less mandrel and configured to drive said first piston in a first direction along said longitudinal axis to move said first compressing ring against said one end of said first packing element and compress said first packing element against said first stop ring so that said packing element is compressed and expands outwardly from said mandrel to form a seal in the borehole; and said drive mechanism being configured to drive said second piston in a second direction along said longitudinal axis opposite said first direction and move said second compressing ring against said one end of said second packing element and compress said second packing element against said second stop ring so that said packing element is compressed and expands outwardly from said mandrel to form a seal in the borehole.
According to another aspect of the invention, there is provided a method for setting a plurality of packers on a wellbore string, the method comprising: operating a first wellbore packer by exposing a mechanism of the first wellbore packer to annular pressure; and delaying the setting of a second wellbore packer that is axially spaced along the wellbore string from the first wellbore packer until after operating the first wellbore packer.
According to another aspect of the invention, there is provided an apparatus for fluid treatment in a wellbore, the apparatus comprising: a tubing string having a long axis and including a wall portion defining an inner bore therein; a first packer operable to seal about the tubing string and mounted on the tubing string; a second packer operable to seal about the tubing string and mounted on the tubing string in a position axially offset along the tubing string from the first packer; and a packer setting mechanism for selectively operating sequentially the first packer and the second packer toward setting.
According to another aspect of the invention, there is provided a method for securing a tubing string in a wellbore, the method comprising: running a tubing string into the wellbore, wherein the tubing string includes a long axis, a wall portion defining an inner bore; a first packer operable to seal about the tubing string and mounted on the tubing string; a second packer operable to seal about the tubing string and mounted on the tubing string in a position axially offset along the tubing string from the first packer; positioning the tubing string in the wellbore forming an annulus between the tubing string and a wall of the wellbore; and selectively operating the first packer and the second packer sequentially by application of annular fluid pressure.
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

Referring to the drawings, several aspects of the present invention are illustrated by way of example, and not by way of limitation, in detail in the figures, wherein:

FIG. 1 is a sectional view through a wellbore packer according to an embodiment of the present invention;

FIGS. 2(a) to 2(f) illustrate operation of a magnetic switch to set a packer in accordance with an embodiment of the present invention.

FIGS. 3(a) to 3(d) illustrate a method according to an embodiment of the present invention.

FIG. 4 illustrates another method according to an embodiment of the present invention.

In the drawings, like reference numerals indicate like elements.

DETAILED DESCRIPTION OF THE EMBODIMENTS

The description that follows and the embodiments described therein are 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. In the description, similar parts are marked throughout the specification and the drawings with the same respective reference numerals. The drawings are not necessarily to scale and in some instances proportions may have been exaggerated in order more clearly to depict certain features.
The present application discloses a packer that is set by hydraulic conditions in the annulus and a wellbore string and methods in this regard. In one embodiment, a packer is disclosed that does not require a through-mandrel setting port, i.e. a port or opening through which fluid communicates outwardly from the mandrel inner diameter (ID). According to an embodiment, the packer is set using a hydraulic configuration responsive to annular hydrostatic pressure, for example, in one embodiment as described in more detail below. According to one aspect, the packer mandrel comprises a port-less, end-to-end steel tubular with all moving parts on the outside of the packer. It will be appreciated that one advantage of not having a port in the mandrel is that a possible leak point is avoided. For example, when a tubing string carrying a no-port packer is pressurized, for example, during fracturing operations or the like, the packer and/or the setting cylinder are not subjected to the pressurization, which decreases the likelihood of a pressure-based breach in the mandrel. As described in more detail below, the hydraulic arrangement provides a mechanism for activating the packer in a position in the wellbore without requiring pressurization of the tubing string inner diameter on which the packer is carried and without communication of that inner diameter pressure through the wall of the packer mandrel to the packer setting mechanism. Stated another way, the mechanism for setting the packer may be operated in response to annular pressure without communicating tubing string pressure through the mandrel wall. In one embodiment, for example, the packer may be triggered and driven to set while the normal, natural tubing string pressure for that depth (hydrostatic pressure) is maintained in the tubing string.
For example, a method is taught for installing a packer to create a seal in a wellbore defined by a wellbore wall, the method comprising: running the packer into a wellbore, the packer installed in a tubing string and including a mandrel, a packing element encircling the mandrel and a setting mechanism for the packing element; positioning the packer in the wellbore adjacent an open hole section of the wellbore wall to create an annular area between the packer and the wellbore wall; setting the packer while preventing tubing string pressure from passing through the mandrel to the packer setting mechanism and while maintaining at least hydrostatic pressure in the annular area; and allowing the packing element to expand to create a seal in the annular area between the tubing string and the open hole section of the wellbore wall.
In the method, preventing may include selecting the packer to have no packer setting port through the mandrel such that pressure cannot be communicated from the tubing string to the setting mechanism; setting may include applying a compressive setting force to the packing element and/or setting may occur after a timer expires.
The method may further comprise increasing pressure in the annulus to treat the wellbore and increasing pressure may include increasing a setting force applied to the packing element and/or triggering the packer to set and there may be a time delay between triggering and setting.
The method may employ a configuration wherein a second packer is carried on the tubing string and is axially spaced along the tubing string from the packer and prior to setting, the second packer is operated in response to annular pressure. Alternately or in addition, positioning may position the second packer uphole from the packer and setting may occur before the second packer is set or positioning may position the second packer downhole from the packer and setting occurs before the second packer is set.
Additionally, a wellbore installation for a wellbore is taught comprising: a tubing string including a frac port; and a wellbore packer connected into the tubing string and forming an annular seal in the wellbore separating a first annular area accessed through the frac port from a second annular area, the wellbore packer including: a port-less mandrel having a longitudinal axis; a packing element encircling said mandrel; a setting mechanism coupled to said port-less mandrel including a piston configured with a compressing ring proximate one end of the packing element, and a stop ring proximate another end of said packing element, said stop ring being affixed to said mandrel and configured to block movement of said packing element, the setting mechanism configured to be responsive to a driving force to drive the piston in a first direction along said longitudinal axis to move said compressing ring against said one end of said packing element and compress said packing element against said stop ring so that said packing element is compressed and expands outwardly from said port-less mandrel to form the seal in the wellbore; and a port for communicating fluid from the first annular area to the piston.
Additionally, a wellbore packer is taught for creating a seal in a borehole. The wellbore packer may include: a port-less mandrel having a longitudinal axis; first and second packing elements encircling said mandrel in a spaced relationship along said longitudinal axis; a first piston configured with a first compressing ring proximate one end of said first packing element, and a first stop ring proximate another end of said first packing element, said first stop ring being affixed to said mandrel and configured to block movement of said first packing element; a second piston configured with a second compressing ring proximate one end of said second element, and a second stop ring proximate another end of said second packing element, said second stop ring being affixed to said mandrel and configured to block movement of said second packing element; a drive mechanism coupled to said port-less mandrel and configured to drive said first piston in a first direction along said longitudinal axis to move said first compressing ring against said one end of said first packing element and compress said first packing element against said first stop ring so that said packing element is compressed and expands outwardly from said mandrel to form a seal in the borehole; and said drive mechanism being configured to drive said second piston in a second direction along said longitudinal axis opposite said first direction and move said second compressing ring against said one end of said second packing element and compress said second packing element against said second stop ring so that said packing element is compressed and expands outwardly from said mandrel to form a seal in the borehole.
The packer may further include a locking mechanism comprising a locking ratchet, said first piston being configured with a reciprocal ratchet for engaging said locking ratchet, said second piston being configured with a reciprocal ratchet for engaging said locking ratchet, and said locking ratchet being configured to prevent bi-directional movement of said first and said second pistons. The first piston may comprise a piston skirt and the second piston may comprise a piston skirt having an exterior surface, and the piston skirt of said first piston may be positioned around the exterior surface of the piston skirt of said second piston and configured in an overlapping and telescoping arrangement. The borehole in which the packer is to be used comprises an open hole section, and the wellbore packer may be configured to set the packing elements in said open hole section.
Methods are also taught for setting the one or more packing elements in an open hole section of a borehole.
In one embodiment, the packer includes a packing element that, when triggered, sets to create a seal in the annulus about the string, which includes the mandrel on which the packing element is carried. When setting, the packing element expands radially outward to fill the space between the liner and the wellbore wall, which may be casing in a cased hole or exposed formation in an open hole. The packing element may be set by a setting mechanism that operates by mechanical compression or by swelling.
In an embodiment where the packing element is set by mechanical compression, the compression may be by stroking of a setting mechanism. Stroking of the setting mechanism applies a force against the packing element such that the packing element is axially compressed and it extrudes outwardly. Where the packing element is set by swelling, a setting mechanism may expose the swellable element to fluid that causes it to expand. In one embodiment, the swellable element is normally isolated, as by a covering, from a hydraulic fluid that causes swelling of the packing element, and when the packer is triggered, the packing element that is swellable is exposed to that fluid so that swelling begins. The setting mechanism for a swellable packer may include a stroking mechanism, a burst mechanism, etc.
The setting mechanism is responsive to a driver. For example, stroking of a setting mechanism could be by any of various drivers including fluid pressure drives, electrical drives, biasing members, etc. A fluid pressure drive may be due to any of various pressurizing events such as (i) by total wellbore pressure, which is the normal annular pressure for a well depth (hydrostatic), (ii) by increasing pressure in the annulus, (iii) by release of pressurized fluid such as from a nitrogen charge, (iv) by a fluid producing event (primer cord), etc. An electrical drive may be generated by a motor powered by a battery or an electrical conductor.
Some packers set when exposed to the driver. Other packers set only when activated to do so by a triggering mechanism. In such embodiments, the triggering mechanism causes the driver to move the setting mechanism. A triggering mechanism can include one or more of various mechanisms. Since a packer is intended to create a seal in a wellbore, the triggering mechanism may be selected to be activated when the packer is positioned downhole. As such, the triggering mechanism may be responsive to downhole conditions, to only cause the packer to set when the triggering mechanism arrives downhole, and/or the triggering mechanism may be responsive to a signal initiated from surface to only allow setting when a signal is communicated from surface and received by the triggering mechanism and/or the triggering mechanism may only cause the packer to set when an appropriate time has lapsed, for example, to only allow the packer to set when time has passed sufficient to ensure that the packer is downhole.
According to one embodiment, for example, the packer includes a setting mechanism responsive to a pressure driver of annular pressure, for example, annular hydrostatic pressure. The setting mechanism is configurable to be released and driven by the pressure drive and, for example, may include a stroking mechanism including a low pressure, for example atmospheric, chamber and a hydraulic chamber that can be exposed to a pressure drive to act against the atmospheric chamber. The stroking mechanism can be part of a hydraulic cylinder that acts against the atmospheric chamber, as driven by the pressure drive and, when activated, can compress the packing element conventionally like a mechanically activated packer. In such an embodiment, the packing element, setting mechanism and driver may be installed on the outside of the mandrel. The packer further includes a triggering mechanism that is activated to expose the hydraulic pressure chamber to the pressure drive. Thus, the setting mechanism is released and driven by the driver, when the triggering mechanism is activated to set the packing element.
Reference is first made to FIG. 1, which shows a wellbore packer according to one embodiment and indicated generally by reference 100. The wellbore packer 100 comprises a mandrel 110, one or more packing elements (here two are shown indicated individually by references 120 a and 120 b), a hydraulically driven setting mechanism 130 and a mechanical body lock 140.
In use, the mandrel 110 is connected at its ends into a tubing string 111 and positioned in a borehole. According to an embodiment, the borehole comprises an open hole section such that at least wellbore wall 112 adjacent the packer is open hole, uncased, with the formation exposed. An annulus 113 is formed between the packer and wall 112.
The mandrel 110 comprises a tubular wall defining therein an inner diameter ID. According to an embodiment, the mandrel 110 comprises a port-less configuration, i.e. the mandrel does not include a port through its wall thickness in communication with the inner diameter for providing a pressurization path to the packer. Wellbore packer 100 is set using a driver other than direct communication through a mandrel port of the tubing string inner diameter ID pressure to the setting mechanism. As will be described in more detail below, the illustrated wellbore packer 100 is set using a pressurized fluid, but without the requirement for pressure communication from the inner diameter ID through the mandrel 110 to the packer setting mechanism.
The packing elements 120 a, 120 b comprise extrudable packing elements. According to an exemplary implementation, the packing elements 120 a, 120 b are annular and formed of an elastomer, for example, rubber. According to another aspect, the packing elements 120 a, 120 b comprise an enlarged cross section in the set position (for example, as depicted in FIG. 2(f)) and the increased expansion ratio allows the packing elements 120 a, 120 b to be set in oversized holes.
As shown in FIG. 1, the packing element 120 a is mounted between a fixed stop ring 150 a and a compressing ring 152 a. Similarly, the second packing element 120 b is mounted on the mandrel 110 between a fixed stop ring 150 b and a compressing ring 152 b. According to an exemplary implementation, the hydraulically actuated setting mechanism 130 comprises a port 142 which provides fluid access from a nitrogen charge 144 to a hydraulic chamber 146 which is defined between a first piston 160 and a second piston 162. The hydraulically actuated setting mechanism 130 is configured with a triggering mechanism indicated generally by reference 148. In operation, the nitrogen charge 144 comprises nitrogen under pressure which is released in response to activation by the triggering mechanism 148 to create a pressure drive.
In operation, actuation of the triggering mechanism 148 results in a release of nitrogen from the nitrogen charge 144 which generates fluid pressure in chamber 146, which drives the first piston 160 against the first compressing ring 152 a and compresses the first packing element 120 a against the first fixed stop ring 150 a. The compression of the packing element 120 a causes outward expansion. Similarly, actuation of the triggering mechanism 148 drives the second piston 162 against the second compressing ring 152 b and compresses the second packing element 120 b against the second fixed stop ring 150 b. The compression of the packing element 120 b causes outward expansion to create a seal in the wellbore.
According to an embodiment, the first piston 160 includes a skirt 163, which encloses the hydraulic chamber between the two pistons 160 and 162 and is configured to telescopically ride over the second piston 162. According to another aspect, the wellbore packer 100 includes seals 170 which are configured to prevent leakage of fluid between the piston assemblies and into chamber 146.
According to an embodiment, the mechanical body lock system 140 comprises a ratchet mechanism as shown in FIG. 1. The ratchet mechanism 140 is configured between the skirt 163 of the first piston 160 and the second piston 162 and permits the pistons 160, 162 to move away from each other, i.e. in response to fluid pressure of the released nitrogen charge resulting in the compression of the respective packing elements 120, but prevents the pistons 160, 162 from moving back towards each other, i.e. back into the initial positions. According to an exemplary implementation, each of the pistons 160, 162 includes a reciprocal ratchet or latch that engage in the ratchet mechanism 140 to prevent reverse movement of the pistons. By preventing reverse movement of the pistons 160, 162, the ratchet mechanism 140 effectively locks the packing elements 120 a, 120 b into a compressed, expanded configuration.
As shown in FIG. 1, the fixed stop ring 150 a can include shears indicated generally by reference 172. The shears 172 are configured to mount or affix the fixed stop ring 150 a to the mandrel 110. According to another aspect, the shears 172 are configured to shear or break, for example, when the tubing string is pulled up, this releases the fixed stop ring 150 a which in turn releases the compressive force on the packing elements 120 a, 120 b.
Triggering mechanism 148, that causes setting mechanism 130 to stroke, can include one or more of various mechanisms. For example, it is generally desired that the triggering mechanism may be selected to allow the packer to stroke only when the packer is positioned downhole. Thus, the triggering mechanism (i) may be responsive to downhole conditions, to only set when it arrives downhole, and/or (ii) may be timed to set only when a particular time has passed, that time being sufficient to ensure that the packer is downhole and/or (iii) may be responsive to a signal, for example, initiated from surface to only allow stroking when the signal is communicated from surface.
As an example of a triggering mechanism activated by signaling from surface, one embodiment employs a stroking mechanism triggered by pressuring up the annulus. For example, the stroking mechanism may be secured by a shear that can be overcome at a particular pressure. The particular pressure may be, for example, above hydrostatic conditions (so the packer is not driven to set by simply running into the hole) but below fracing pressures, such that the formation is not broken down (i.e. fraced) by setting the packer. In particular, normally when a packer is run there is fluid or drilling mud in the hole, the weight of which can be determined. Therefore, it is possible to calculate the height or static pressure of the mud or fluid column in the annulus. This pressure is determined by how much height or static pressure is required to maintain control of the well, including control of the pressure of the gas or hydrocarbons in the well. A packer installed in a well can be run that has a pressure activated setting cylinder set to activate at a particular pressure, which is higher than the pressure generated by the height or static pressure of the mud. Therefore, as the packers are run on the string into the well and after they are positioned, they remain in the unset position. However, when the packers are properly positioned and it is appropriate to set them, pressure is applied through the annulus up to fracturing pressure, which may be several thousand PSI higher than the hydrostatic pressure created by the mud weight. So, the setting cylinder can be set to trigger and stroke at a pressure somewhere between the hydrostatic pressure of the mud and the fracturing pressure of the formation.
Once the packers are in the correct position in the well, the particular pressure may be achieved by “pressuring up” the annulus, as by adjustment from surface. In particular, pressure could be applied to the annulus between the tubing string and the wellbore wall in communication with the packer.
In such an embodiment, the increased annular pressure may be employed as the triggering mechanism, but may also be employed as the driver. For example, the annular fluid may be communicated to a piston and a pressure differential could be generated against an atmospheric chamber in the stroking mechanism to drive compression of the packing element. Alternately, the pressuring up can simply trigger the packer operation, for example, permit operation of the setting mechanism and, thereafter, the pressure can be dissipated before a driver, such as hydrostatic pressure, is employed to actually set the packer.
When annular pressure (i.e. hydrostatic, pressure pulses, or pressured-up conditions) is employed to operate, such as to trigger or to set, a packer, it may be important to ensure that the annular pressure is able to be properly and reliably communicated to that packer. For example, if annular pressure is employed to operate a plurality of packers on a string in a wellbore, premature setting and pressure isolation, caused by setting of one of the plurality of packers before another of the plurality of packers can adversely impact the installation of the string and the wellbore methods.
Setting of a packer radially expands the packer element to create a seal in the annulus. This packer-established seal is intended to seal against pressure and fluid communication through the annulus and, thus, can isolate operative annular pressure from another packer.
For example, consider a simple example of two spaced apart packers, including an uphole packer and a downhole packer below the uphole packer, in a well. If hydrostatic pressure is employed to operate the two spaced apart packers, setting of the uphole packer before the downhole packer can set, can modify, for example reduce, the hydrostatic pressure at the downhole packer such that it may fail to set. The same can be true if the packers are set by an annular-fluid-conveyed signal, such as for example, pressurization or a pressure pulse. If the two packers rely on the annular-fluid-conveyed signal from a source and one of the packers sets between the source of the signal and the other packer, the signal can be isolated from ever reaching the other packer. Therefore, according to an aspect of the invention, a packer mechanism may be employed to ensure that the two spaced apart packers are pressure operated sequentially (i.e. one after another). The packer mechanism may take various forms and may include one mechanism for each packer or a component that serves both. The mechanism may include any of mechanical, electrical, electronic and/or software components. The sequential order of the packer operation may be selected depending on the source of the annular pressure activation. For example: (i) if the packers are operated (i.e. triggered or set) by hydrostatic pressure, the packers may be operated sequentially starting with the lowest (most downhole) packer along the string and the setting may move up from there; (ii) if the packers are operated (i.e. triggered or set) by an annular-fluid-conveyed signal from surface conveyed down through the annulus, the packers may each have a mechanism to ensure sequential setting starting with the lowest (most downhole) packer along the string and the setting operations may move up from there; or (iii) if the packers are operated (i.e. triggered or set) by an annular-fluid-conveyed signal conveyed from below and which comes up through the annulus, the packers may each have a mechanism to ensure sequential operation starting with the most uphole packer (i.e. the one closest to surface) and the annular pressure driven operation may move down from there from packer to packer. It will be appreciated that if it is the triggering that requires exposure to annular pressure, but the actual setting does not, then in the sequential operation, a second packer may be set to isolate the first packer before the first packer is actually set, provided sufficient time is provided for exposure of the first packer to annular pressure for triggering thereof.
In a method for setting a plurality of packers on a wellbore string, the method may comprise: operating a first wellbore packer by exposing an operating mechanism of the first wellbore packer to annular pressure; and delaying the setting of a second wellbore packer that is axially spaced from the first wellbore packer until after the first wellbore packer is operated. Thus, the packers are operated sequentially by annular pressure wherein the first wellbore packer is operated first and then the second wellbore packer is operated to set.
Thus, with reference to FIGS. 3(a) to 3(d), a wellbore string 311 may carry a plurality of wellbore packers 300 a, 300 b, 300 c that are operated, for example triggered to set or set, in response to wellbore annular pressure. On such a string, packers 300 a, 300 b and 300 c are axially offset from each other along the string. Some packers are downhole of other packers, for example, packer 300 a is the lower-most packer being downhole of packer 300 b and packer 300 c and packer 300 c is closest to surface, with packers 300 b and 300 a downhole thereof.
The string may include other tools such as a liner hanger 396, wellbore treatment ports 398 and/or a toe sub 399.
The string is positioned (FIG. 3(a)) in a well 312 while the packers remain unset. An annulus 313 is formed, which is the space between the string and the wellbore wall.
If the string inner diameter is not already pressure isolated, for example, if toe sub 399 was open for circulation during run in, toe sub 399 may be closed.
A method for setting the plurality of annular pressure responsive packers 300 a, 300 b, 300 c on wellbore string 311, may include delaying the setting of the upper packers until the lowermost packer's pressure-responsive operation is carried out by annular pressure. This packer operation may be triggering and/or setting the packer. Thus, for example as illustrated in FIG. 3(b), triggering and/or setting a first wellbore packer, such as lowermost packer 300 a, by exposing a mechanism, such as a triggering mechanism or setting mechanism, of the first wellbore packer to annular pressure P proceeds ahead of the setting of a second wellbore packer, such as packer 300 b, that is uphole from the first wellbore packer.
If there is more than one packer above the lowermost annular pressure set packer, such as is illustrated here, the setting of all packers above the lowermost packer should be delayed until any operation that requires annular pressure is completed for packer 300 a.
In the same way, if packer 300 b, which is below packer 300 c requires hydrostatic pressure or annular pressure signaling for its operation, packer 300 c is delayed from setting, and thereby sealing annulus 313, until packer 300 b is operated by annular pressure FIG. 3(c).
Finally, as shown in FIG. 3(d) the uppermost packer 300 c can be set to create another isolated annular region 313 b in the wellbore.
If liner hanger 396 has a packer component, the setting of uppermost packer 300 c creates another isolated annular region 313 c.
Annular pressure set packers may be biased towards the pressure source. Since packers 300 a to 300 c are set by pressure from above, the pressure-responsive operating mechanism, such as a pressure responsive chamber, may face uphole toward surface so that pressure from above can access it, even if the packer is already partially set.
As may be noted, a liner hanger such as liner hanger 396 is employed to securely hold the liner in the well and may include an anchoring mechanism, such as slips, to expand out and engage the surrounding wall (casing C, as shown, or the wellbore wall) at the location where the liner hanger is positioned. Additionally, liner hanger 396 may include a packer for well control, to isolate annular pressure below the liner hanger from conditions above. Thus, since the packers 300 a to 300 c are set from annular pressure above, if liner hanger 396 includes a packer, it may be necessary to consider the liner hanger operation in the above-noted method.
In one embodiment, therefore, string 311 may be held in place without setting liner hanger until packers 300 a to 300 c are set. In such an embodiment, a work string, for example, may be employed to hold string 311. As such liner 311 is held steady during the packer setting operations. The liner hanger may be set last.
In another embodiment, at least the packer portion of the liner hanger is not set until the packers in the annulus below are operated by annular pressure. Thus, the annular pressure remains live to the packers below the liner hanger and the packers can be set. Thereafter, the liner hanger packer may be set to finally seal the annulus at the upper end of liner 311. In such an embodiment, the slip portion of the liner hanger may be set first before the packers are set or the whole string may be held simply by a work string. Either way, the liner 311 is held steady during the packer setting operations. If the slips are set first, a slip arrangement can be used that allows fluid communication therepast. Such a method allows the work string to be pulled out of the hole after the anchoring mechanism is set.
Alternately, in another embodiment, the packer of the liner hanger can be set to create a seal in the annulus. This will close off the annulus 313 below liner hanger 396 to pressure from above. In such an embodiment, a communication port 397 can be provided below (downhole of) the seal of the liner hanger. After installation of the liner and setting of liner hanger, port 397 can be opened (FIG. 3(b)) to provide access from the inner diameter of the string to annulus 313 such that pressure can be communicated to the packers 300 a to 330 c. Then the packer setting operation for packers 300 a to 300 c, as noted above, can proceed. Once the packers are set, the communication port 397 can be closed. This method, whereby the liner hanger packer is set before initiating the packer setting operations, allows the work string to be pulled out of the well before setting the packers and ensures that the well is secured at an early stage in the wellbore operations: before initiating other wellbore operations.
FIG. 4 shows another wellbore string 411 that carries a plurality of wellbore packers 400 a, 400 b, 400 c. Packers 400 a, 400 b and 400 c are axially offset from each other along the string. Some packers are downhole of other packers, for example, packer 400 a is the lower-most packer being downhole of packer 400 b and packer 400 c and packer 400 c is the most uphole packer, being closest to surface with packers 400 b and 400 a downhole thereof.
The string may include other tools such as wellbore treatment ports 498, a liner hanger and/or a toe sub 414. To facilitate illustration, packer 400 a may be considered an independent packer or a packer of a liner hanger.
The string is positioned in a well 412. An annulus 413 is formed between the string and the wellbore wall.
In this embodiment, packers 400 a, 400 b, 400 c are operated (triggered or set) in response to wellbore annular pressure and wellbore annular pressure is adjusted by pressure communication through the strings inner diameter ID, which opens to annulus 413 at an opening such as a port in toe sub 414 at the toe 411 a of the string. For example, as shown by arrows F1, a pressure increase in the annulus may be caused, and/or a fluid conveyed signal may be transmitted, via the fluid in the string's inner diameter, through the port in toe 411 a and then through annulus 413 to the packers. Thus, the pressure source for annular-pressure operation of the packers is the toe 411 a of the string.
A method for setting the plurality of annular pressure responsive packers 400 a, 400 b, 400 c on wellbore string 411 may include preventing the lower packers from setting until the upper packer's annular-pressure responsive operation is carried out by annular pressure. This packer operation may be triggering and/or setting the packer. Thus, triggering and/or setting a first wellbore packer, such as uppermost packer 400 c (shown already set), by exposing a mechanism, such as a triggering mechanism or setting mechanism, of that wellbore packer to pressure F1 in the annulus proceeds ahead of the setting of a second wellbore packer, such as packer 400 a and/or packer 400 b, that is downhole from the uppermost wellbore packer 400 c.
The uppermost packer 400 c, even if it is a liner hanger packer, may be set first. In one embodiment, it may be desirable to independently set the liner hanger to ensure the well is secured. Thus, while the uppermost packer 400 c is herein disclosed as being annular pressure operated, the liner hanger packer may not be annular set and/or may be set apart from the packer sequencing method.
It will be appreciated that if any of the packers below the uppermost packer set before the uppermost packer is able to respond to annular pressure, those lower packers can isolate and prevent the proper operation of the uppermost packer. Thus, if there is more than one packer below the uppermost annular pressure set packer, such as is illustrated here, the setting of all packers below the uppermost packer should be delayed until any operation that requires annular pressure is completed for packer 400 c.
In the same way, therefore, if packer 400 b, which is above packer 400 a, requires annular pressure signaling for its operation, packer 400 a is delayed from setting, and thereby sealing annulus 413, until packer 400 b is operated by annular pressure.
Finally, the lowermost packer 400 a can be set to create another isolated annular region 413 b in the wellbore.
The pressure communication to packers 400 a to 400 c is provided through the toe sub. When the packers are finally pressure operated, the toe sub 414 may be closed to prevent flow into or out of the liner at that point. Thus, in one embodiment, the sequencing operation for setting the packers may be followed by closing the toe sub 414, to close the port therein.
To achieve sequential setting, the packers, such as the packers of FIGS. 3 and 4, may each include mechanisms: with receivers that receive unique operating signals to set only when signaled; timers; and/or delay setting mechanisms, such as metering devices, etc. Many such options are listed herein below.
To close a toe sub, such as the toe sub 414 of FIG. 4, after the packers, there can be various options as well, such as those noted above and those described in more detail below. The easiest option is likely to include the use of a timer for the toe sub, which is set to only close the toe sub after the last packer has set. In particular, the toe sub may be electronic with a timer controlling closing of a valve for the toe sub. The timer may be set to have a delay time longer than any delay time for the packers 400 a to 400 c. The timer may be started at surface or from the same signal received by the packers. Of course, if desired, the toe sub can be closed in other, more manual ways. Some options include hydraulic closing, closing by dropping a ball, mechanically with wireline or another work string.
For example, a method where the timing of the setting of the annular pressure responsive packers is sequential and where lower packers are set first, may be accomplished by providing each packer that is to be sequentially set with a unique triggering signal, such that one packer, for example, the lowermost unset pressure responsive packer, is triggered uniquely of the packers above it. Alternately or in addition, timers may be used to trigger the sequential packer setting so that packers are not set uphole before a packer therebelow can respond to annular pressure. Alternately or in addition, a delay setting mechanism can be provided on packers uphole of a packer whose operation is responsive to annular pressure such that while the packers may be triggered at the same time, the setting of some packers is delayed beyond the setting of other, lower packers. The delay setting mechanism may actually be a timer.
For example, to avoid problems of premature setting or problems of pressure isolation (caused by setting of some packers uphole before other packers downhole can respond to annular pressure, such as hydrostatic pressure or an annular fluid conveyed signal to set), a delay setting mechanism may be employed to delay stroking for a period after it is triggered. A delay, for example, may be useful in a string where a plurality of packers is to be set by pressuring up the annulus. The delay may allow all packers to reach full setting pressure (for example, just below fracturing pressure), prior to the packers actually setting. Such a system can include a triggering device, a setting mechanism responsive to a driver and a delay mechanism to allow the packer to be triggered but actually delay the final setting of the packer.
A mechanism to delay the setting of packers can be configured to act after triggering to resist movement of the packer setting mechanism to its fully set position until after a selected time has lapsed. That selected time is longer than the setting mechanism would take to move to the set position if the delay mechanism was not employed.
For example, in a packer where the packer setting mechanism is actuated to begin the setting process by a pressure responsive triggering mechanism, the delay mechanism may be configured to act after actuation by a pressure trigger to delay final setting of the packers, until after a selected time has lapsed. In one embodiment, the delay mechanism may include a hydraulic chamber that meters movement of the hydraulic fluid therein to gradually allow a release of a hydraulic fluid. For example, while the setting cylinder can move toward the open position, it is slowed in that movement by the resistance exerted by a delay metering hydraulic chamber between a moveable part of the closure and another fixed part of the closure system. For example, the moveable part may carry a valved piston that moves through the hydraulic chamber as the closure is opened. The valved piston slows movement of the moveable part corresponding to the rate at which the hydraulic fluid in the chamber may pass through the valve's fluid orifice. According to one embodiment, the delay mechanism is adjustable to control the degree of resistance imparted thereby. For example in an embodiment, employing a hydraulic chamber, the viscosity of the hydraulic fluid and/or the size of the valve orifice can be selected, to control the metering effect of the mechanism.
The delay system may work with a driver that provides the energy to move the closure to the open position, after it is actuated. The driver may include one or more of a motor, a biasing member such as a spring or a pressure charge (i.e. a nitrogen chamber charge or an atmospheric pressure chamber), differential pressures, etc. While the driver may be capable of applying a force to rapidly move the setting cylinder, the delay mechanism resists and therefore slows such movement. A driver may permit the setting cylinder to be moved without maintaining the original pressure drive that initiated the movement. For example, if the trigger is by pressuring up the annulus, the pressure may be dissipated but the driver continues to apply a driving force to the setting cylinder. In one embodiment, the driver is selected to operate apart from the trigger. For example, the driver may be a biasing member that generates or stores energy that can only be dissipated after the setting cylinder is actuated to begin opening.
The above-noted reference to use of a delay device is with respect to a pressure driven trigger. However, it is to be understood that the delay device may operate with other triggers, such as those employing signaling apart from annular pressure signaling, as described in greater detail herein below.
While annular pressure drive may be convenient, the porosity of some formations may render it difficult to reliably pressure up the annulus. As such, stroking triggers may include other mechanisms that can be operated while hydrostatic pressure remains unmodified such that the packer can be effectively triggered even in boreholes containing open hole sections where it may be advisable to avoid pressuring up the annulus.
In particular, signals other than pressuring up the annulus could be initiated from surface, such as those employing sound frequency, a radio signal, a pressure pulse, a vibrational shock wave, etc., that are sensed by the triggering mechanism and cause the driver to set the packer. The signals could be conveyed through the annulus or through the tubing string.
A pressure pulse could be communicated through the string inner diameter to be sensed by a strain gauge of the triggering mechanism. The strain gauge senses the slight mandrel expansion generated by the pressure pulse. Alternately, the triggering mechanism may include a pressure sensitive button in the inner diameter of the mandrel that is responsive to the pressure pulse and communicates to the triggering mechanism. Of course, any port through which fluid may pass from the mandrel at the packer should be avoided.
A sound/vibration shock wave, sometimes termed a ping, may be generated from surface or as a result of a surface signal that communicates through the material of the string to a sensor of the triggering mechanism. For example, a shock wave can be generated by a mechanical strike applied to the liner at surface.
According to another embodiment, the triggering mechanism comprises a temperature responsive mechanism. For example, the triggering mechanism exhibits a different thermal contraction and expansion characteristic, so that when the tool assembly heats up, it expands to catch the trigger mechanism, and once it cools back down, the packer activates an external port and allows the atmospheric over hydraulic chamber to stroke and pack off the packing elements. The temperature fluctuations can be driven from surface to drive the thermal cycling of the temperature responsive mechanisms. One possible embodiment operates in response to a temperature change in the well bore to allow the driver, such as a mechanism configured to act against an atmospheric chamber to set the packing element. For example, an expandable piece of metal could be built into the cylinder and the expandable piece of metal can expand or contract under temperature applications. In one embodiment, the metal piece expands and lengthens along with the rest of the packer when heated, but when cooled down, it would contract more than the other components to thereby set the packer. For example, all packer components may expand approximately the same distance or coefficient as the system heats up when run down hole but when cool down begins, the mechanism sets up the packer. In normal wellbore operations, wellbore temperatures of 100 degrees F. or to 150 degrees F. are typically encountered, and some sites can reach around 300 degrees F. Once the liner is in place, the system could be treated to a cool down operation. Cool down of the liner may be achieved during pumping operations, such as during a circulating operation or while fracing the well. In either case, after all the parts including the packer, the mandrel and the expandable metal piece are heated, cooling can set the packer, such as by shifting the stroking cylinder to the open position.
Yet another embodiment employs a triggering mechanism with a timer, which can be set to trigger the packer at a particular time to expand the packing elements. For example, an electronic timer may be incorporated into the packer and may be configured to trigger the packer to set after a particular delay. For example, based on the expected time for installation of the string, a time may be selected (i.e. 24 to 48 hours after the system is installed) after which the mechanism activates the setting mechanism to set. If the packers are to be set sequentially (i.e. one at a time), the timer for each packer may have a different selected time. For example, a packer to set first such as packer 400 c may have its timer configured with a shorter time than the timer for packer 400 a, while the timer for packer 400 b has a configuration to set at some time in between. The timers for the packers may be turned on before running the tubing string with the packer systems into the well.
In another embodiment, timers may be used to delay the actual setting after triggering. For example, a packer may be signaled to set, but a timer may delay the actual setting. As such, the timers for the packers may not actually be turned on before running the packer system into the well, but may later be turned on and then the packers will set in sequence according to the individual time for each packer.
In another embodiment, the trigger may be responsive to an activating tool, such as a drop bar or plug, such as a ball or dart, released by or from surface and passed through the mandrel of the packer. The tool may emit a signal picked up by the triggering mechanism such as, for example, a radio frequency signal emitter, an RF ID tag, or the like which would be carried on a pump down or dropped tool and a sensor, such as a radio frequency sensor, can sense the tag and communicate to other components of the triggering mechanism which in turn cause the driver to act on the packer setting mechanism to set the packing elements. For example, the sensor may activate electronics of the triggering mechanism which in turn opens a port or detonates a charge or causes a hydraulic cylinder to stroke and expand the packer. Such a system may require a battery pack to power the sensor and electronics.
For example, reference is next made to FIGS. 2(a) to 2(f), which show another embodiment of a wellbore packer. This packer has a driver based on annular pressure and a triggering mechanism responsive to a signal communicated from surface, which in this embodiment is a signal communicated via a tool conveyed through the tubing string to the packer.
The wellbore packer is indicated generally by reference 200 and includes a packing element 220 on a mandrel 210, a hydraulic chamber 246 openable via a conduit 286 to a chamber 244 that is open to annular pressure, an atmospheric chamber 247, a piston 260, a fixed stop ring 250, a compressing ring 252 and seals 270.
The wellbore packer further includes a magnetic activation mechanism 280 (which is a triggering mechanism) comprising a magnetic switch 282. The magnetic switch 282 is operatively coupled to a hole opener 284, such as a valve, which is operatively coupled to conduit 286 between the chamber 244 and chamber 246. As shown, the magnetic activation mechanism 280 also includes a battery 287. The hole opener 284 in a closed position prevents the fluid pressure from being communicated from chamber 244 to chamber 246, as indicated by arrow A in FIG. 2(b). In response to actuation by the magnetic switch 282, the hole opener 284 moves to an open position and allows fluid to flow from the chamber 244 into chamber 246 as indicated by arrow B in FIG. 2(e). According to an embodiment, the battery 287 is operatively coupled to the hole opener 284 and energizes the hole opener 284 to reconfigure from the closed position to the open position. The annular fluid pressurizes the chamber 246 and creates a pressure differential against atmospheric chamber 247 to move the piston 260 in the direction of arrow C (FIG. 2(e)) which moves the compressing ring 252 against the packing element 220 and compresses the packing element against the fixed stop ring 250, as shown in FIG. 2(f). In this position, the packing element 220 is expanded outwardly to fill the annulus and seal against the wall 212 of the wellbore. Slips (not shown) may also be driven outwardly by this compressive force.
The magnetic switch 282 is activated by exposure to a magnetic field. According to an embodiment, a tool is passed through the mandrel configured with a magnetic component that emits a magnetic field and activates the magnetic switch 282 when moved in the proximity of the switch 282. For example, a tool such as a ball or dart, indicated generally by reference 290 in FIG. 2(c), is configured with a magnetic component capable of activating the magnetic switch 282. The dart 290 is brought, by dropping, pumping, etc. through the tubing string inner diameter ID, into proximity with the magnetic switch 282 and magnetic switch 282 is actuated by the magnetic field emitted from the dart 290. Then, as described above, the magnetic switch 282 actuates the hole opener 284, the chamber 246 is pressurized by fluid from the annulus and the piston 260 is driven in the direction of arrow C (FIG. 2(e)) to compress and outwardly expand the packing element 220 (i.e. “set” the packing element 220) as illustrated in FIG. 2(f).
In one embodiment, hole opener 284 may operate in response to power being applied thereto. For example, when the magnetic field is applied to switch 282, the switch completes a circuit, for example, through contacts that become closed such that power can be provided from battery 287 to hole opener 284, to cause the hole opener to open.
As noted above, the packer setting operation may include a delay mechanism wherein there is a delay between the packer being triggered and the packer actually setting. In the illustrated embodiment of FIG. 2, for example, a delay mechanism such as timer 292 (FIG. 2(d)) may operate delay operation of hole opener 284 to open fluid communication to chamber 246 for a period of time after plug 290 actually activates switch 282.
The above-noted packer is an example of a packer that can be set employing hydrostatic pressure, since the atmospheric chamber is isolated and can be selected to be less than hydrostatic. Thus the packer is useful even in open hole conditions such as where the porosity of the formation may render it difficult to reliably pressure up the annulus.
Packer 200 is a no-port packer since there is no port through mandrel 210 for communicating tubing string pressure from the inner diameter ID to the packer setting mechanism for initial setting of the packer. In other words, at least while setting the packer, tubing string pressure is isolated from the packer setting mechanism.
Packer 200, as disclosed, may therefore be set initially by annular pressure. However, packer 200 may be employed on a string intended for wellbore treatment and may, therefore, be installed on a string with a frac port 298 adjacent the packer. Frac port 298 may be offset axially along the tubing string in which the packer is installed. Frac port 298 may be normally closed by a closure, such as a sleeve 299. However, the frac port can be opened to communicate treatment fluids into annulus 213 to treat the formation at wall 212.
In such an embodiment, packer 200 is initially set while tubing pressure is isolated from the setting mechanism, the packer may have its setting force increased when frac pressures are applied through port 298. In particular, while frac port 298 is normally closed, as during run in, the frac port can be opened by moving sleeve 299, for example after setting the packer, to permit tubing string pressure to be communicated into the annular area 213. For example, the packers disclosed herein may be useful in frac operations wherein after the packer is set (FIG. 2(f)) to create a seal and isolate annular area 213 from an annular area 213 a on the other side of the packing element 220, a pressure well above hydrostatic may be introduced to the annulus 213 between the packer and wellbore bore wall with the intention to frac, and therefore break down, the formation at wall 212. By placing the pressure communication port, in this case conduit 286, in a position where frac pressure is communicated to it from annulus 213, pressures much greater than annular hydrostatic, which was used to set the packer, is communicated to chamber 246 and will act against chamber 247 to further compress packing element 220. As such, when annulus 213 is fraced, the packer's setting force will be increased.
Frac pressure can only be employed to increase the setting pressure if the packer has a piston exposed to frac pressure, as shown in FIG. 2(f). For example, in an embodiment such as that of FIG. 1, packing elements 120 a, 120 b, when set, create a pressure isolated wellbore area therebetween to which frac pressure will not be communicated. If it was desired to provide the packer of FIG. 1 with a setting mechanism responsive to annular frac pressures after initial setting, a pressure responsive piston open to annular pressure could be provided adjacent ring 150 a and/or ring 150 b.
It will be appreciated that according to the port-less packer configuration as described above, the packer setting is initiated through application of energy supplied by any of various drivers and a triggering mechanism, to cause setting of the packer when required. Even though there is a frac port 298, there is no port through the mandrel through which initial packer communication, for example setting pressure, is communicated from the inner diameter to the packer mechanism. Thus the packer is a port-less packer. Once the trigger is activated, the driver energy is communicated to the setting mechanism which, then in turn, mechanically sets the packer. As described above, a number of triggering mechanisms can be utilized as described above, including thermal couplings, electronics, a timing mechanism, a radio frequency mechanism, etc.
In a method, the packer including its packing components (elements, driver, etc.) and a no-port or port-less mandrel, is installed in a tubing string, the string is run into a borehole to a selected position in the borehole, the packer is triggered (i.e. as described above) to be driven to expand and seal against the borehole wall to create a seal in an annulus between the string and the borehole wall. Some consideration may be given to borehole conditions when selecting the triggering mechanism. According to an exemplary application, the borehole comprises an open hole section, and the triggering mechanism selected is a mechanism suitable for an open hole application, i.e. a triggering mechanism that is operated without requiring conditions that would hinder the formation exposed in an open hole wellbore. According to another aspect, after initial setting, frac pressure is communicated to a setting mechanism to increase the setting force for the packer.
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 known 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

What is claimed is:

1. A method for setting a plurality of packers on a wellbore string, the method comprising:

operating a first wellbore packer by exposing a mechanism of the first wellbore packer to annular pressure; and

delaying the setting of a second wellbore packer that is axially spaced along the wellbore string from the first wellbore packer until after operating the first wellbore packer.

2. The method of claim 1 wherein operating includes at least one of triggering and setting.

3. The method of claim 1 wherein delaying includes triggering the second wellbore packer only after operating the first wellbore packer.

4. The method of claim 1 wherein delaying includes awaiting the expiration of a timer to ensure that operating the first packer proceeds before setting the second packer.

5. The method of claim 1 wherein delaying includes operating a delay mechanism after triggering.

6. An apparatus for fluid treatment in a wellbore, the apparatus comprising:

a tubing string having a long axis and including a wall portion defining an inner bore therein;

a first packer operable to seal about the tubing string and mounted on the tubing string;

a second packer operable to seal about the tubing string and mounted on the tubing string in a position axially offset along the tubing string from the first packer; and

a packer setting mechanism for selectively operating sequentially the first packer and the second packer toward setting.

7. The apparatus of claim 6 wherein the packer setting mechanism comprises a hydraulically actuated mechanism.

8. The apparatus of claim 6 wherein the packer setting mechanism is operable in response to fluid pressure communicated to the setting mechanism from outside the tubing string.

9. The apparatus of claim 6 wherein the packer setting mechanism is operable in response to annular fluid pressure.

10. The apparatus of claim 6 wherein the packer setting mechanism is operable in response to hydrostatic pressure.

11. The apparatus of claim 6 wherein the packer setting mechanism is operable in response to a signal conveyed through the annular fluid.

12. The apparatus of claim 6 wherein the packer setting mechanism is for selectively triggering at least one of the first packer and the second packer to set.

13. The apparatus of claim 6 wherein the packer setting mechanism is for selectively setting at least one of the first packer and the second packer.

14. A method for securing a tubing string in a wellbore, the method comprising:

running a tubing string into the wellbore, wherein the tubing string includes a long axis, a wall portion defining an inner bore;

a second packer operable to seal about the tubing string and mounted on the tubing string in a position axially offset along the tubing string from the first packer;

positioning the tubing string in the wellbore forming an annulus between the tubing string and a wall of the wellbore; and

selectively operating the first packer and the second packer sequentially by application of annular fluid pressure.

15. The method of claim 14 wherein selectively operating includes triggering a packer to set.

16. The method of claim 14 wherein selectively operating includes setting a packer.

17. The method of claim 14 wherein the first packer is downhole of the second packer and annular fluid pressure is hydrostatic pressure and selectively operating includes operating the first packer in response to hydrostatic pressure before setting the second packer.

18. The method of claim 14 wherein selectively operating includes conveying a pressure signal from surface to the first packer and the second packer.

19. The method of claim 18 wherein conveying a pressure signal includes increasing the annular fluid pressure and/or conveying a pressure pulse.

20. The method of claim 18 wherein the pressure signal is conveyed downwardly through the annulus.

21. The method of claim 20 wherein the first packer is downhole of the second packer and selectively operating includes operating the first packer in response to the pressure signal before setting the second packer.

22. The method of claim 18 wherein the pressure signal is conveyed through the inner bore and upwardly through the annulus.

23. The method of claim 22 wherein the first packer is downhole of the second packer and selectively operating includes operating the second packer in response to the pressure signal before setting the first packer.

24. The method of claim 14 wherein after operating, the first packer and the second packer create therebetween a first annular wellbore segment substantially isolated from other portions of the annulus.