US20080314591A1

US20080314591A1 - Single trip well abandonment with dual permanent packers and perforating gun

Info

Publication number: US20080314591A1
Application number: US11/766,647
Authority: US
Inventors: John H. Hales; John D. Burleson; Gavin H. Drummond; Flint R. George
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2007-06-21
Filing date: 2007-06-21
Publication date: 2008-12-25
Also published as: EP2006486A2; BRPI0802170A2; EP2006486A3

Abstract

A method of abandoning a well includes the steps of: assembling a tool string including a perforating gun interconnected between first and second packer assemblies; conveying the tool string into a wellbore in a single trip into the wellbore; setting the first packer assembly; setting the second packer assembly; firing the perforating gun; and flowing cement into an annulus longitudinally between the first and second packer assemblies. A system for abandoning a well includes a tool string configured for conveyance into a wellbore in a single trip into the wellbore, the tool string including a perforating gun interconnected between first and second packer assemblies, each of the first and second packer assemblies including a permanent packer.

Description

BACKGROUND

The present invention relates generally to operations performed and equipment utilized in conjunction with a subterranean well and, in an embodiment described herein, more particularly provides a single trip well abandonment system and method with dual permanent packers and perforating gun.
Wells are sometimes abandoned for various reasons. Sometimes, a reservoir or productive zone has become depleted, so that it no longer is economical to produce hydrocarbons from the reservoir or zone. If the well is an injection well, then the need for such injection may no longer exist.
Typical abandonment operations utilize multiple trips into a wellbore to set plugs or packers, perforate, cement, etc. Unfortunately, each trip into the wellbore is very expensive in terms of cost and time.
Therefore, it will be appreciated that a need exists for advancements in the art of well abandonment.

SUMMARY

In carrying out the principles of the present invention, systems and methods are provided which solve at least one problem in the art. One example is described below in which only a single trip into a wellbore is required to perform an abandonment operation. Another example is described below in which a tool string is uniquely configured for use in abandoning a well.
In one aspect, a method of abandoning a well is provided. The method includes the steps of: assembling a tool string including a perforating gun interconnected between two packer assemblies; conveying the tool string into a wellbore in a single trip into the wellbore; setting the packer assemblies; firing the perforating gun; and flowing cement into an annulus longitudinally between the packer assemblies.
In another aspect, a system for abandoning a well is provided. The system includes a tool string configured for conveyance into a wellbore in a single trip into the wellbore. The tool string includes a perforating gun interconnected between two packer assemblies. Each of the packer assemblies includes a permanent packer.
In yet another aspect, a method of abandoning a well is provided which includes the steps of:
assembling a tool string including first and second packer assemblies; conveying the tool string into a wellbore in a single trip into the wellbore; setting the first packer assembly; setting the second packer assembly; and flowing cement into an annulus longitudinally between the first and second packer assemblies.
These and other features, advantages, benefits and objects will become apparent to one of ordinary skill in the art upon careful consideration of the detailed description of representative embodiments of the invention hereinbelow and the accompanying drawings, in which similar elements are indicated in the various figures using the same reference numbers.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1-5 are schematic partially cross-sectional views of a single trip well abandonment system and method embodying principles of the present invention, the system and method being shown as successive steps of the method are performed;

FIGS. 6A-H are enlarged scale cross-sectional views of successive axial sections of an abandonment tool string embodying principles of the invention and which may be used in the system and method of FIGS. 1-5;

FIG. 7 is an elevational view of a J-slot profile which may be used in an anchoring device of the tool string of FIGS. 6A-H;

FIGS. 8A-C are cross-sectional views of a setting tool and packer assembly which is used in the tool string of FIGS. 6A-H; and

FIG. 9 is a schematic cross-sectional view of an alternate embodiment of the system and method of FIGS. 1-5.

DETAILED DESCRIPTION

It is to be understood that the various embodiments of the present invention described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of the present invention. The embodiments are described merely as examples of useful applications of the principles of the invention, which is not limited to any specific details of these embodiments.
In the following description of the representative embodiments of the invention, directional terms, such as “above”, “below”, “upper”, “lower”, etc., are used for convenience in referring to the accompanying drawings. In general, “above”, “upper”, “upward” and similar terms refer to a direction toward the earth's surface along a wellbore, and “below”, “lower”, “downward” and similar terms refer to a direction away from the earth's surface along the wellbore.
Representatively illustrated in FIGS. 1-5 is a well abandonment system 10 and associated method which embody principles of the present invention. The system 10 and method allow a well abandonment operation to be performed in only a single trip, thereby substantially reducing the cost and time required to perform the operation.
As depicted in FIG. 1, the system 10 includes a perforating gun 14 interconnected between two packer assemblies 16, 18. These components are part of a tool string 12 which may be conveyed into the wellbore 20 by a work string 34 (such as drill pipe, production tubing, coiled tubing, etc.). Other types of conveyances (such as wireline, slickline, etc.) may be used instead, if desired.
Preferably, each of the packer assemblies 16, 18 includes a permanent packer 24, 26. Permanent packers are designed for permanent installation in a well, and do not include release mechanisms such as those used to release retrievable packers.
In FIG. 1, the perforating gun 14 and packer assemblies 16, 18 are being conveyed into the wellbore 20 using the work string 34. A valve 40 of the upper packer assembly 18 may be open at this time to permit fluid circulation through the work string 34.
In FIG. 2, the tool string 12 has been appropriately positioned in the wellbore 20 at a desired depth. The lower packer 24 is set to isolate the wellbore 20 below the packer.
To set the lower packer 24, a setting tool 42 is used which sets the packer in response to compression of the tool string 12 by applying set down weight to the tool string. An anchoring device 28 (not shown in FIG. 2, see FIGS. 6G & H) is included in the tool string 12 and grips the wellbore 20 below the packer 24 to allow set down weight to be applied to the setting tool 42.
After the packer 24 has been set, the setting tool 42 releases from the packer 24. This allows the remainder of the tool string 12 to be displaced upwardly in the wellbore 20 away from the packer 24.
In FIG. 3, the perforating gun 14 and upper packer assembly 18 have been displaced upwardly away from the lower packer 24, so that the distance between the packers 24, 26 is increased. The upper packer 26 is then set in the wellbore 20.
Preferably, the upper packer 26 is set by rotating the work string 34 from the surface. For this purpose, a conventional rotational packer setting tool 106 (see FIG. 6A) may be included in the work string 34. However, other methods of setting the upper packer 26 may be used, if desired.
In FIG. 4, the perforating gun 14 has been fired (e.g., by detonating explosive shaped charges therein) to thereby form perforations 38 through casing 44 lining the wellbore 20. The perforating gun 14 is preferably fired by applying increased pressure to a conventional pressure operated firing head 36 connected to the perforating gun.
However, other methods of firing the perforating gun 14 may be used, if desired. In addition, if perforations 38 already exist, then there may be no need to include the perforating gun 14 in the tool string 12. Therefore, it is not always necessary to include the perforating gun 14 in the tool string 12.
In FIG. 5, cement 22 and any abandonment fluids have been flowed through the work string 34 to the tool string 12, and out of the open valve 40 into the wellbore 20 between the packers 24, 26. The cement 22 also flows into the perforations 38, and any abandonment fluids may also flow into the annulus behind the casing and into the formation surrounding the wellbore 20.
The work string 34 is then separated from the tool string 12, which causes the valve 40 to close. The cement 22 is allowed to harden in the annulus 98 and perforations 38 between the packers 24, 26, and in the annulus behind the casing and in the formation.
The cement 22 is preferably a cementitious material, but as used herein, the term “cement” can include any hardenable fluid or slurry. For example, epoxies, other polymers, etc. may be used in place of, or in addition to, cementitious material.
Once the cement 22 has hardened, the system 10 forms an isolation barrier in the annulus 98 and wellbore 20 which securely prevents fluid communication through the wellbore. Further details of the system 10 and the tool string 12 are provided below, but it should be clearly understood that the principles of the invention are not limited to any of the details described above or below, in part because many variations are possible for performing the methods and constructing the systems of the present invention.
A representative example of one embodiment of the tool string 12 is illustrated in FIGS. 6A-H, apart from the remainder of the system 10. The tool string 12 is depicted in FIGS. 6A-H in its run-in configuration, that is, while the tool string is being conveyed into the wellbore 20.
When the tool string 12 has been appropriately positioned for setting the lower packer assembly 16, the anchoring device 28 is actuated to cause slips 46 to grippingly engage the wellbore 20 (i.e., the interior of the casing 44 lining the wellbore). In other embodiments, slips 46 may not be used in the anchoring device 28. Instead, other gripping elements (such as a swellable locator plug, etc.) could be used.
In the illustrated example, the anchoring device 28 is actuated by reciprocating the tool string 12 up and down in the wellbore 20 to operate a ratchet or J-slot device 50 which includes a lug 48 engaged in a J-slot profile 52 formed on an inner mandrel 54 of the anchoring device.
An enlarged view of the mandrel 54 and profile 52 are illustrated in FIG. 7. When the lug 48 enters a particular portion of the profile 52, further downward displacement of the tool string 12 causes a conventional drag block 108 carried on the mandrel 54 to bias a sleeve 56 in which the lug 48 is installed upwardly against the slips 46, thereby radially outwardly displacing the slips along an inclined surface of a conical wedge 58.
This causes the slips 46 to grip the interior of the casing 44 and prevent further downward displacement of the tool string 12 in the wellbore 20. Compressive force (e.g., set down weight) may now be applied to the tool string 12 by slacking off on the work string 34 at the surface.
Compression in the tool string 12 activates the setting tool 42 to set the lower packer 24. In FIG. 6E it may be seen that shear pins 60 releasably secure a plunger 62 relative to a reservoir housing 64 of the setting tool 42. A piston 66 is reciprocably received in the housing 64 between the plunger 62 and a reservoir of hydraulic fluid 68.
Sufficient compressive force in the tool string 12 will shear the pins 60 and cause the plunger 62 to apply the compressive force to the piston 66, thereby pressurizing the fluid 68. The pressurized fluid 68 is in communication with an annular chamber 70 via an inner passage 72 formed through a mandrel 74.
Enlarged views of the setting tool 42 and the lower packer 24 are illustrated in FIGS. 8A-C. In FIG. 8A it may be seen that the chamber 70 is formed axially between a piston 30 and a bulkhead 76. The piston 30 is secured to the mandrel 74 and is reciprocably received in an outer housing 78.
The interior of the housing 78 above the piston 30 is exposed to pressure in the wellbore 20 via an opening 80. Referring again to FIG. 6E, the interior of the housing 64 is also exposed to pressure in the wellbore 20, and so initially the fluid 68 is at wellbore pressure.
However, when the compressive force is applied by the plunger 62 to the piston 66 as described above, a pressure increase results in the fluid 68. This increased pressure in turn results in a multiplication of force due to the difference in areas between the pistons 66, 30, so that an increased upwardly directed biasing force is applied to the mandrel 74 by the piston 30.
The upwardly directed biasing force is transmitted as a tensile force from the mandrel 74 of the setting tool 42 to an inner mandrel 32 of the lower packer 24 via a shear sleeve 82. Simultaneously, the compressive force in the tool string 12 is applied via the housing 78 of the setting tool 42 to an upper ring 84 of the packer 24.
As a result, upper and lower slips 86, 88 are driven onto respective conical wedges 90, 92 and seal elements 94 are compressed between the wedges. The slips 86, 88 grip the interior of the casing 44, and the seal elements seal against the interior of the casing, thereby setting the packer 24.
When sufficient tensile force is applied to the shear sleeve 82, it shears and thereby releases the setting tool 42 from the lower packer 24. In this manner, the remainder of the tool string 12 may be displaced upward away from the set packer 24 as depicted in FIG. 3.
After the upper portion of the tool string 12 has been appropriately positioned in the wellbore 20, the upper packer 26 (depicted in FIGS. 6A & B) is set. Setting the upper packer 26 is similar in many respects to setting the lower packer 24, in that a compressive force is applied to an upper ring 84 and a tensile force is applied to an inner mandrel 32 via a shear sleeve 32.
However, these forces are preferably applied to set the upper packer 26 using a conventional rotational packer setting tool 106 of the type well known to those skilled in the art which is connected at the lower end of the work string 34. An example of such a rotational packer setting tool is the Mechanical Setting Tool available from Halliburton Energy Services, Inc. of Houston, Tex. and used for setting the Halliburton EZ Drill SV squeeze packer.
Setting the upper packer 26 results in slips 86, 88 gripping the interior of the casing 44, seal elements 94 sealing against the interior of the casing, and shearing of the shear sleeve 82 to thereby release the work string 34 from the tool string 12. At this point, the valve 40 (see FIG. 6B) still permits fluid communication through a sidewall of the upper packer assembly 18, but otherwise the wellbore 20 is isolated between the set packers 24, 26.
The perforating gun 14 is then fired by applying pressure to the firing head 36 (see FIG. 6C). To accomplish this step, increased pressure is applied to the work string 34 at the surface, and this pressure is communicated to the firing head 36 via an internal passage 96 of the tool string 12.
The firing head 36 is preferably a conventional pressure operated firing head which causes detonation of explosive charges in the perforating gun 14 in response to application of a predetermined fluid pressure to the firing head. Another pressure operated firing head could alternatively, or in addition, be connected to a lower end of the perforating gun 14, in which case increased pressure could be communicated to the firing head via the open valve 40 and the annulus 98 between the tool string 12 and the wellbore 20.
After the perforating gun 14 is fired and the perforations 38 are thereby formed (see FIG. 4), the cement 22 is pumped through the work string 34 to the tool string 12, and out of the valve 40 into the annulus 98 and the remainder of the wellbore 20 between the packers 24, 26. The cement 22 also flows into the perforations 38 (see (FIG. 5) and into the annulus outside of the casing.
The work string 34 is then raised, thereby applying an upwardly directed force to a hollow stinger rod 100 in the upper packer 26. The stinger 100 displaces upward with the work string 34, thereby upwardly displacing a valve sleeve 102 of the valve 40, and closing the valve. The stinger 100 is retrieved from the well with the work string 34.
When the valve 40 is closed, the wellbore 20 between the packers 24, 26 is isolated from the remainder of the wellbore. The cement 22 is allowed to harden in this isolated portion of the wellbore 20 and the annulus outside of the casing 44, forming an isolation barrier in the wellbore and the annulus outside of the casing, at which point the well is abandoned or at least isolated from the surface.
If there are existing open perforations below the upper packer 26 prior to firing the perforating gun 14, then in order to apply increased pressure to the firing head 36, the valve 40 may be closed by raising the work string 34 a sufficient distance to shift the sleeve 102 and close the valve.
At this point, the increased pressure may be applied to the passage 96 to actuate the firing head 36. After the perforating gun 14 has been fired, the valve 40 may be reopened by lowering the work string 34, to thereby allow the cement 22 to be flowed into the wellbore 20 between the packers 24, 26 and into the annulus outside of the casing 44.
An alternative configuration of the system 10 is representatively illustrated in FIG. 9. This configuration is similar in many respects to the system 10 described above (compare FIG. 9 to FIG. 3), in that it includes the perforating gun 14 positioned between the packer assemblies 16, 18.
In addition, the well abandonment method using the system 10 of FIG. 9 is substantially similar to the method described above. However, instead of the valve 40, a perforated nipple 104 provides for fluid communication through a sidewall of the tool string 12.
Thus, the method using the system 10 of FIG. 9 does not include the step of closing the valve 40. Instead, the hardened cement 22 can effectively close off the perforated nipple 104 and isolate the wellbore 20 and the annulus outside of the casing 44 between the set packers 24, 26. Alternatively, a vent or sliding sleeve-type valve could be used below the upper packer assembly 18.
Other alternatives are available, as well, for the system 10 of FIGS. 1-9. For example, the system 10 could use drill pipe, production tubing, coiled tubing, wireline (electric line) or slickline as a conveyance.
Control over positioning the tool string 12 at appropriate depths in the wellbore 20 could be through use of pipe measurements, by tagging an existing component (such as a bridge plug or casing shoe) in the wellbore, or by using sensors and/or measuring devices (such as a wheel counter, pressure sensor, temperature sensor, or combination thereof) incorporated into the tool string. A suitable example of an on-board autonomous navigation system for downhole tools is described in U.S. Published Application No. 2005-0269083.
The anchoring device 28 which allows compressive force to be applied to the tool string 12 to set the lower packer 24 could be a mechanical slip assembly, a collar stop (which engages a collar recess in the casing 44) or a swellable packer assembly. Alternatively, the tool string 12 could tag the bottom of the wellbore 20, or a bridge plug, etc. As another alternative, a cast iron bridge plug could be used in place of the lower packer 24 and anchoring device 28.
The lower packer 24 could be set using compressive force, such as set down weight as described above, using compressive force without the hydraulic force multiplier, using tensile force, using pressure applied via a control line, etc. Setting of the lower packer 24 could be controlled by telemetry (e.g., electromagnetic, pressure pulse, acoustic, etc.) and/or other means (e.g., timer, accelerometer, temperature/pressure/depth sensor, etc.) to allow setting the packer by hydrostatic or applied pressure, ignition of a propellant or explosive charge, etc. An electric line may be used to initiate ignition of a propellant or explosive charge, or to operate an electric motor or valve, to set the packer 24, if desired. Similar techniques could also be used for setting the upper packer 26, instead of the rotational packer setting tool 106 described above.
If tensile force is to be used to set a packer, the setting mechanism could be operated by first setting a tension-type mechanically operated slip assembly (similar to the anchoring device 28 turned upside-down). With the slip assembly set, the packer setting mechanism could then be operated by pulling tension in the tool string 12 using the work string 34. For example, this tensile force could be used to remove hydrostatic pressure from one side of a setting piston and create an atmospheric chamber on another side of the piston, allowing well hydrostatic pressure to bias the piston and set the packer. Or, the tensile force could be used to set the packer without use of applied pressure.
An electric line could be used to operate a solenoid valve or other type of valve to open a port and allow use of hydrostatic pressure to actuate the setting tool. Electricity could be used to generate heat to cause one or more thermostats to operate valves in the setting tool. Valves can be opened to expose a piston to increased (e.g. well hydrostatic) or reduced pressure (e.g., atmospheric pressure) to operate a setting tool.
If tensile or compressive force in the tool string 12 is not used to initiate setting of either of the packers 24, 26, then use of the anchoring device 28 may not be required. For example, if a packer is set using hydrostatic pressure, or pressure applied via a control line or the work string 34, or if a packer is set by igniting a propellant or explosive, or by electric motor, then it may not be necessary to use the anchoring device 28 to permit application of tensile or compressive force to the tool string 12.
The perforating gun 14 could be an explosive jet perforating gun made of any material (e.g., aluminum, steel, composite, strip, etc.) and may include any type of explosive shaped charge (e.g., big hole or deep penetrating, etc.). Alternatively, the perforations 38 could be formed by bullets, lasers, water jet or other type of perforating device.
Therefore, it should be clearly understood that the present invention is not limited at all to any particular details of the system 10, tool string 12 and methods described above. Instead, a large variety of alternatives exist for carrying out the principles of the invention.
It may now be fully appreciated that the above detailed description provides advancements in the art of well abandonment. In particular, a method of abandoning a well is provided in which the method includes the steps of: assembling a tool string 12 including a perforating gun 14 interconnected between two packer assemblies 16, 18; conveying the tool string 12 into a wellbore 20 in a single trip into the wellbore; setting the packer assemblies 16, 18; firing the perforating gun 14; and flowing cement 22 into the annulus 98 between the packer assemblies 16, 18 and into the annulus outside of the casing 44.
The assembling step may include providing permanent packers 24, 26 in the packer assemblies 16, 18.
The first packer assembly 16 may be set by reciprocating the tool string 12 in the wellbore 20 to grippingly engage an anchoring device 28 in the wellbore, and then compressing the tool string against the anchoring device to set the packer assembly. The tool string 12 compressing step may further include using a compressive force to apply fluid pressure to a piston 30 to thereby apply a tensile force to a mandrel 32 of the packer assembly 16.
The second packer assembly 18 may be set by rotating a work string 34 releasably attached to the tool string 12. Alternatively, the second packer assembly 18 may be set by applying pressure to the packer assembly.
The perforating gun 14 may be released from a packer 24 of the first packer assembly 16 after the first packer assembly is set, and prior to setting the second packer assembly 18.
The perforating gun 14 firing step may include applying pressure to a firing head 36 of the tool string 12. The cement 22 flowing step may include flowing cement into perforations 38 formed by the perforating gun 14, and into the annulus outside of the casing 44.
The tool string 12 may be conveyed on a work string 34, and a valve 40 of the packer assembly 18 may be closed in response to separating the tool string from the work string after the cement 22 flowing step.
A system 10 for abandoning a well may include a tool string 12 configured for conveyance into a wellbore 20 in a single trip into the wellbore. The tool string 12 may include a perforating gun 14 interconnected between two packer assemblies 16, 18. The packer assemblies 16, 18 may include permanent packers 24, 26.
The packer assembly 16 may also include a setting tool 42 which applies pressure to set the permanent packer 24 in response to compression of the tool string 12. The packer assembly 16 may include an anchoring device 28 for grippingly engaging the wellbore 20 prior to setting the permanent packer 24.
The system 10 may include a work string 34 engaged with the tool string 12 for conveying the tool string into the wellbore 20. The packer assembly 18 may include a valve 40 which closes in response to separation of the work string 34 from the tool string 12. The valve 40 selectively permits and prevents fluid flow through a sidewall of the packer assembly 18.
The perforating gun 14 may be releasable from the permanent packer 24 of the packer assembly 16 after the packer is set.
The system 10 may include cement 22 flowed into the wellbore 20 between the packer assemblies 16, 18 and hardened therein. The cement 22 may extend into perforations 38 formed by the perforating gun 14, and into an annulus outside of the casing 44.
The system 10 may include a firing head 36 which initiates firing of the perforating gun 14 in response to pressure applied to the firing head.
Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the invention, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to these specific embodiments, and such changes are within the scope of the principles of the present invention. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the present invention being limited solely by the appended claims and their equivalents.

Claims

1. A method of abandoning at least a portion of a well, the method comprising the steps of:

assembling a tool string including a perforating gun interconnected between first and second packer assemblies;

conveying the tool string into a wellbore in a single trip into the wellbore;

setting the first packer assembly;

setting the second packer assembly;

firing the perforating gun; and

flowing cement into an annulus longitudinally between between the first and second packer assemblies.

2. The method of claim 1, wherein the assembling step includes providing a permanent packer in each of the first and second packer assemblies.

3. The method of claim 1, wherein the first packer assembly setting step further comprises reciprocating the tool string in the wellbore to grippingly engage an anchoring device in the wellbore, and then compressing the tool string against the anchoring device to set the first packer assembly.

4. The method of claim 3, wherein the tool string compressing step further comprises using a compressive force to apply fluid pressure to a piston to thereby apply a tensile force to a mandrel of the first packer assembly.

5. The method of claim 1, wherein the second packer assembly setting step further comprises rotating a work string releasably attached to the tool string.

6. The method of claim 1, wherein the second packer assembly setting step further comprises applying pressure to the second packer assembly.

7. The method of claim 1, further comprising the step of releasing the perforating gun from a packer of the first packer assembly after the first packer assembly setting step, and prior to the second packer assembly setting step.

8. The method of claim 1, wherein the cement flowing step further comprises flowing cement into perforations formed by the perforating gun.

9. The method of claim 1, wherein the cement flowing step further comprises flowing cement into an annulus outside of casing lining the wellbore.

10. The method of claim 1, wherein the perforating gun firing step further comprises applying pressure to a firing head of the tool string.

11. The method of claim 1, wherein the conveying step further comprises conveying the tool string on a work string, and further comprising the step of closing a valve of the second packer assembly by separating the tool string from the work string after the cement flowing step.

12. A system for abandoning at least a portion of a well, the system comprising:

a tool string configured for conveyance into a wellbore in a single trip into the wellbore, the tool string including a perforating gun interconnected between first and second packer assemblies, each of the first and second packer assemblies including a permanent packer.

13. The system of claim 12, wherein the first packer assembly further includes a setting tool which applies pressure to set the permanent packer of the first packer assembly in response to compression of the tool string.

14. The system of claim 12, wherein the first packer assembly further includes an anchoring device for grippingly engaging the wellbore prior to setting the permanent packer of the first packer assembly.

15. The system of claim 12, further comprising a work string engaged with the tool string for conveying the tool string into the wellbore, and wherein the second packer assembly includes a valve which closes in response to separation of the work string from the tool string.

16. The system of claim 15, wherein the valve selectively permits and prevents fluid flow through a sidewall of the second packer assembly.

17. The system of claim 12, wherein the perforating gun is releasable from the permanent packer of the first packer assembly after the permanent packer of the first packer assembly is set.

18. The system of claim 12, further comprising cement flowed into the wellbore between the first and second packer assemblies and hardened therein.

19. The system of claim 18, wherein the cement extends into perforations formed by the perforating gun.

20. The system of claim 18, wherein the cement extends into an annulus outside of casing lining the wellbore.

21. The system of claim 12, further comprising a firing head which initiates firing of the perforating gun in response to pressure applied to the firing head.

22. A method of abandoning at least a portion of a well, the method comprising the steps of:

assembling a tool string including first and second packer assemblies;

conveying the tool string into a wellbore in a single trip into the wellbore;

setting the first packer assembly;

setting the second packer assembly; and

flowing cement into an annulus longitudinally between the first and second packer assemblies.

23. The method of claim 22, wherein the assembling step further comprises interconnecting a perforating gun between the first and second packer assemblies.

24. The method of claim 23, further comprising the step of forming perforations in the wellbore by firing the perforating gun, and wherein the cement flowing step further comprises flowing cement into the perforations.

25. The method of claim 23, further comprising the step of releasing the perforating gun from a packer of the first packer assembly after the first packer assembly setting step, and prior to the second packer assembly setting step.

26. The method of claim 22, wherein the cement flowing step further comprises flowing cement into perforations between the first and second packer assemblies.

27. The method of claim 22, wherein the cement flowing step further comprises flowing cement into an annulus outside of casing lining the wellbore.

28. The method of claim 22, wherein the assembling step includes providing a permanent packer in each of the first and second packer assemblies.

29. The method of claim 22, wherein the first packer assembly setting step further comprises reciprocating the tool string in the wellbore to grippingly engage an anchoring device in the wellbore, and then compressing the tool string against the anchoring device to set the first packer assembly.

30. The method of claim 29, wherein the tool string compressing step further comprises using a compressive force to apply fluid pressure to a piston to thereby apply a tensile force to a mandrel of the first packer assembly.

31. The method of claim 22, wherein the conveying step further comprises conveying the tool string on a work string, and further comprising the step of closing a valve of the second packer assembly by separating the tool string from the work string after the cement flowing step.