Reliable Sleeve Activation for Multi-Zone Frac Operations Using Continuous Rod and Shifting Tools

Abstract

An apparatus for opening and closing downhole tools, such as sliding sleeves, includes a first (opening) shifting tool connected to an end of a continuous rod, an intermediate rod connected below the first shifting tool, and a second (closing) shifting tool connected to the end of the intermediate rod. The first tool has a profile for selectively opening sleeves when moved downhole, and the second tool has a profile for selectively closing sleeves when moved uphole. Alternatively, a single tool can couple to the end of the continuous rod and can have the profiles for opening and closing sleeves. When used, the continuous rod and shifting tools are deployed downhole to a series of sliding sleeves on a tool string. Manipulated by the continuous rod and a rig at the surface, the shifting tools are used to successively open and close the sliding sleeves so that successive isolated zones of a formation can be treated with frac fluid.

Description

BACKGROUND

Selectively fracing multiple zones of a formation improves the production capabilities of a well. The equipment string for such a frac operation uses a series of packers to sequentially isolate different zones of a downhole formation. Sliding sleeves on the tubing string position between each of the packers and provide exit ports for frac fluid to interact with the adjacent zones of the formation. Performing successive frac treatments on the isolated zones requires the sliding sleeves to be opened and closed in a desired sequence so that zones of interest can be fraced independently of the other zones. To do this, the frac operation uses several steps. First, one sliding sleeve is opened, while the others remain closed. Frac fluid is pumped downhole and through the open sleeve to interact with the adjacent zone of the formation. When facing is done for this zone, the sliding sleeve is then closed, and another sliding sleeve is opened so the next zone can be treated.

Sliding sleeves can be activated using many types of devices, including balls, darts, and pulling tools. Currently, operators experience problems when performing frac operations For example, the number of zones that can be treated may be limited by the method used to actuate the sleeves. Also, operators can have difficulties ensuring that the proper sleeve is open for the frac treatment and then that the proper sleeve is closed and sealed after that treatment. This difficulty can be even more problematic when fracing a horizontal well.

When balls are used to actuate the sliding sleeves, for example, the frac treatment is applied successively to each isolated zones by selectively opening the sliding sleeves and allowing the treatment fluid to interact with the adjacent zones of the formation. To open each sliding sleeve, operators drop a specifically sized ball into the tubing string and land the ball on a corresponding ball seat on a designated sliding sleeve. Once seated, the ball closes off the lower zone just treated, and built up pressure on the seated ball forces the sliding sleeve open so frac fluid can interact with the adjacent zone of the formation. Operators repeat this process up the tubing string by successively dropping larger balls against larger ball seats in the sliding sleeves.

The required diameters of the ball seats and the required increments between ball sizes limits how many zones can be treated using balls to open the sliding sleeves. For example, the lowermost ball seat must be the smallest, and each shallower seat must be sized slightly larger. In general, the balls can range in size from 1-in. to 3¾-in. Therefore, only a finite number of frac zones can be successfully used when opening the sleeves with balls due to the needed increments between ball sizes to differentiate them from one another. Therefore, actuating sliding sleeves with balls is not practical for frac operations involving several (e.g., more than about eleven) frac zones. In addition to the limit on the number of frac zones that can be handled, using balls and darts to open sliding sleeves only allows for one shot operations. In other words, the balls and darts are only capable of opening the sleeves, which cannot be closed unless another device is used. Finally, any balls and darts used to operate sleeves must be removed either by floating or milling them, which involves time and expense to perform.

Other than balls and darts, a pulling tool connected to wireline can be used to actuate sliding sleeves during a frac operation. However, actuating sliding sleeves using wireline can be limited in horizontal sections downhole. In many cases, wireline has no real pushing capabilities, which limits its use in operating sliding sleeves or other flow control systems within a wellbore.

Using coiled tubing can overcome the limitations of wireline. Unfortunately, a pulling tool on coiled tubing can still have limited access in extended horizontal wellbores, making it difficult for the pulling tool to reach sliding sleeves in horizontal sections. This difficulty is due at least in part to the fact that coiled tubing has some memory inherent in its material. Therefore, the coiled tubing as it is run downhole with the pulling tool is more likely to produce friction within the tubing string in which it is run, making moving the coiled tubing and the pulling tool more difficult. When used under these circumstances, the coiled tubing requires operators to spend an excessive amount of time to locate and subsequently open or close a sliding sleeve—sometime without success altogether. Furthermore, coil tubing is expensive and is preferably removed from the tubing string with each frac treatment to avoid damage to the coil tubing. Finally, the physical nature of coiled tubing inherently limits the coil tubing's ability to operate sliding sleeves by pushing. All of these issues greatly increase the time and cost of performing a frac operation with coiled tubing and make coiled tubing less desirable for operating sliding sleeves.

What is needed is a solution for cycling sliding sleeves open and closed in extended horizontal applications that can be better manipulated from the surface and that is more reliable in opening and closing the sleeves downhole.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic view of a system using continuous rod and a tool actuating device.

FIG. 2A shows a cross-section of a sliding sleeve in a closed condition.

FIG. 2B shows a cross-section of the sliding sleeve in an opened condition.

FIG. 3 shows a tool actuating device on an end of a continuous rod.

FIG. 4A shows an isolated cross-section of an upper (opening) shifting tool for the tool actuating device.

FIG. 4B shows a cross-section of the upper (opening) shifting tool having the continuous rod and an intermediate sucker rod coupled at its ends.

FIG. 5 shows a cross-section of a lower (closing) shifting tool for the tool actuating device.

FIG. 6A shows the upper (opening) shifting tool opening a sliding sleeve initially in the closed (up) condition.

FIG. 6B shows the lower (closing) shifting tool closing a sliding sleeve initially in the opened (down) condition.

FIGS. 7A-7E shows stages of actuating sliding sleeves with the tool actuating device.

FIGS. 8A shows another tool actuating device.

FIG. 8B shows a cross-section of the tool actuating device of FIG. 8A.

DETAILED DESCRIPTION

A system 10 schematically shown in FIG. 1 uses a continuous rod 40 and a tool actuating device 60 to actuate downhole tools during well operations. In the current example, the system 10 is used in conjunction with frac operations, and the continuous rod 40 and tool actuating device 60 allow operators to selectively open and close sliding sleeves 50 downhole. In the typical implementation as shown, a cased borehole 12 passes through a formation, and a tool string 14 installed in the borehole 12 has several sliding sleeves 50 positioned adjacent perforations 13 at various intervals in the cased borehole 12. Packers 20 isolate portions of the annulus 15 of the borehole 12 and string 14 between each section of perorated borehole 12. In this way, frac fluid pumped down the tool string 14 can be diverted by an open sliding sleeve 50 through the isolated perforations 13 to treat the isolated zone of the formation.

As shown, the cased borehole 12 can have an extended horizontal section that makes actuating the sliding sleeves 50 difficult with conventional coiled tubing or wireline techniques. To overcome these difficulties, the tool actuating device 60 is disposed on the distal end of the continuous rod 40, and the rod 40 and device 60 are used together to effectively and reliably open and close the sliding sleeves 50 in such an extended horizontal section. (The system 10 can be used equally as well in vertical applications). In general, the tool actuating device 60 can be moved up or down in the string 14 to selectively actuate a given sleeve 50 between opened and closed conditions by engaging specific profiles on the device 60 with profiles in the sleeve 50. The rigid continuous rod 40 stiffly conveys the desired movement of the device 60 relative to the sleeves 50, making the opening and closing of the sleeves 50 more predictable and ensuring that more complete travel of the sleeves 50 is achieved.

As noted previously, coiled tubing has some memory inherent in its material and produces undesirable friction when conveyed in a horizontal borehole. As a result, operators must spend an unwarranted amount of time attempting to locate and actuate the sliding sleeves downhole—sometimes with no success. However, the continuous rod 40 attempts to straighten out in the tubing string 14 and produces a lower friction component. The reduced friction allows operators to move the tool actuating device 60 as needed with better control from the surface. In this way, the rod 40 and device 60 facilitate frac operations in the horizontal length of the borehole.

As shown, the continuous rod 40 deploys in the tool string 14 to convey the device 60 downhole to the sliding sleeves 50. At the surface, a rig 30 for extended continuous rod is used to manipulate (raise and lower) the continuous rod 40 in the string 14 and thereby move the actuating device 60 relative to the sliding sleeves 50. This rig 30 can be similar to that used with extended continuous rod. For example, the rig 30 can include a reel for the continuous rod 40 and a variable-speed, hydraulically driven gripper mechanism (not shown), and the rig 30 can be adapted to operate like a heavy duty slickline unit at the surface to deploy the continuous rod 40 and device 60 downhole. In addition to the rig 30, other components (not shown), such as wellhead, lubricator, etc., are also used at the surface.

The sliding sleeves 50 can be selectively opened and closed to divert frac fluid in the tubing string 14 to the isolated zone of the annulus 15 between packers 20. An example sliding sleeve 50 shown in FIG. 2A has a housing 52 with an insert 54 movably disposed therein. When closed as shown in FIG. 2A, the insert 54 is positioned toward the lower end of the housing 52. In this position, slots 55 in the insert 54 do not align with ports 53 in the side of the housing 52 so that fluid passing in the sleeve 50 is not diverted outside the sleeve 50 and the tubing to which it is coupled at both ends. When opened as shown in FIG. 2B, the insert 54 is positioned toward the upper end of the housing 52. In this position, the slots 55 in the insert 54 align with the ports 53 in the side of the housing 52 so that fluid passing in the sleeve 50 can be diverted outside the sleeve 50.

To move the insert 54 between the opened and closed conditions, the insert 54 has a lower profile 56 and an upper profile 58 that allow the insert 54 to be engaged and moved within the housing 52. For the present sleeve 50, the lower profile 56 is used to move the insert 54 downward in the housing 52, thereby closing the sleeve 50. By contrast, the upper profile 58 is used to move the insert 54 upward in the housing 52, thereby opening the sleeve 50. A reverse arrangement is also possible in which upward movement of the insert 54 by the upper profile 58 can close the sleeve 50 and downward movement by the lower profile 56 can open the sleeve 50.

With an understanding of the system 10, continuous rod 40, sliding sleeves 50, and tool actuating device 60 provided above, discussion now turns to a more detailed description of the tool actuating device 60. As shown in FIG. 3, the tool actuating device 60 couples to a threaded pin 42 on the continuous rod 40. At top, the device 60 has an upper (opening) shifting tool 100 that couples to the rod's threaded pin 42 using a rod coupling 70. At bottom, the device 60 has a lower (closing) shifting tool 200 that couples below the upper tool 100 using rod couplings 70 and an intermediate length of sucker rod 80. When the continuous rod 40 is moved upper or down in a tubing string, the upper and lower tools 100/200 move together.

In the present example, the upper tool 100 is designed to be the opening tool for opening the sliding sleeves 50 by engaging the upper profile (58) and shifting the insert (54) upward in the housing (50). (See FIGS. 2A-2B). Likewise in this example, the lower tool 200 is designed to be the closing tool for closing the sliding sleeves 50 by engaging the lower profile (56) and shifting the insert (54) downward in the housing (50). (See FIGS. 2A-2B). Thus, the upper shifting tool 100 opens the sleeve 50 by jarring up, and the lower shifting tool 200 closes the sleeve 50 by jarring down. However, a reverse arrangement could also be used. For example, the arrangement of tools 100 and 200 on the device 60 could be switched so that the (closing) shifting tool 200 can be the upper tool and the (opening) shifting tool 100 can be the lower tool. Congruent with this, the sliding sleeves 50 could also be open and closed by respectively shifting down and up—opposite to that shown in FIGS. 2A-2B.

The upper (opening) shifting tool 100 shown in FIG. 4A has a core mandrel 110 with fishneck couplings 102 and 104 threaded at both ends. A biased collet 120 fits around the mandrel's recessed intermediate portion 116 and connects at both ends to stops 112 and 114 fixed to the core mandrel 110. The collet 120 has B-profiles 122 that include an upward facing shoulder 124, an upper (shortened) cam 126, and a lower (extended) cam 128. As discussed in more detail later, the B-profiles 122 enable the collet 120 to engage recessed profiles in the sliding sleeve in one direction and bypass the recessed profiles in the sliding sleeve in the opposite direction. This type of shifting tool is typically referred to as a B shifting tool with a B-profile.

As shown in FIG. 4B, the upper (opening) shifting tool 100 couples to the distal end 42 of the continuous rod 40 using a sucker rod coupling 70. As shown, this coupling 70 has a cylindrical body 72 with internal thread 74 that connects to the rod's threaded pin 42 and to the pin 103 on the tool's upper fishneck coupling 102. The sucker rod coupling 70 can use thread 74 that is preferably cold form-rolled as opposed to cut and can use the PRO/KC design available from Weatherford/Lamb, Inc. As shown, the coupling 70 can also use a center torque button 76 positioned between the threaded pins 42/103 of the rod 40 and fishneck 102 for equal contact pressure of both pin noses. In a similar fashion, another sucker rod coupling 70 couples the tool's lower fishneck 104 to the upper pin on the device's intermediate sucker rod 80.

As with upper tool 100, the lower (closing) shifting tool 200 shown in FIG. 5 includes similar components, including a core mandrel 210 with a fishneck coupling 202 threaded at its top and including a collet 220 fitting around the mandrel's recessed intermediate portion 216 and connected at both ends to stops 212 and 214 fixed to the core mandrel 110. The tool 200 has a nose 204 at its distal end. The collet 220 has B-profiles 222 that include a shoulder 224, an upper cam 226, and a lower cam 228. For this closing tool 200, however, the B-profile 222 is reversed so that the shoulder 224 is downward facing and the upper cam 228 is extended.

Operation of the upper tool's B-profile 122 in opening a sliding sleeve 50 is shown in FIG. 6A. Operators manipulate the upper tool 100 upward in the sleeve's housing 52 using the continuous rod 40 and rig equipment at the surface. The B-profile's (upward-facing) shoulder 124 engages a downward-facing shoulder in the insert's upper recess profile 58. When engaged, further upward movement of the tool 100 moves the insert 54 upward within housing 52 toward an opened condition in which the insert's slots align with the housing's ports so fluid can be diverted. Eventually, full upward movement on the tool 100 causes the upper cam (126) to engage an upper release 59 defined in the housing 52, biasing the collet 120 inward and releasing the shoulder 124 from the insert's profile 58. At this point, the tool 100 can move out of the housing 52 while the insert 54 remains in the opened (upward) condition.

Operation of the lower tool's B-profile 222 in closing the sliding sleeve 50 is shown in FIG. 6B and follows a reversed configuration. Here, the B-profile's (downward-facing) shoulder 224 engages an upward-facing shoulder in the insert's lower recess profile 56. When engaged, further downward movement of the tool 200 moves the insert 54 downward within housing 52 toward a closed condition. Eventually, the lower cam (228) engages a lower release 57 so the shoulder 224 is released and the tool 200 can move out of the housing 52 while the insert remains in the closed (downward) condition.

As discussed above, the continuous rod 40 and tool actuating device 60 can be deployed by a surface rig 30 to open and close sliding sleeves during a frac operation. In stages of a frac operation shown in FIG. 7A-7E, the tool actuating device 60 selectively actuates the various sliding sleeves 50 downhole by successively opening and closing the sleeves 50 to treat isolated zones. Using the continuous rod 40 to manipulate the device 60 is more reliable than using coiled tubing, which would tend to produce more friction and would require more time to actuate the sleeves 50.

As initially shown in FIG. 7A, the sliding sleeves 50 are deployed on the string 14 downhole before the frac operation. Operators couple the upper shifting tool 100 to the distal end of the continuous rod 40, couple the intermediate rod 80 to the bottom of the upper tool 100, and coupled the lower shifting tool 200 to the free end of the intermediate rod 80. Operators then install the device 60 in a lubricator fitted atop the wellhead at the surface and deploy the continuous rod 40 and selective shifting tools 100/200 downhole using the drive and other components of the rig (30; See FIG. 1).

When lowered, the tools 100/200 are passed through each of the sliding sleeves 50A-C, which are initially installed closed on the string 14. The sleeves 50A-C may be deployed with grease or other material packed inside to maintain the sliding inserts (54) in the closed condition in the sleeves 50A-C during deployment. As the tools 100/200 are deployed downhole, they cam past each of the sleeves' inserts (54) without engaging the profiles (56, 58). Eventually, the upper (opening) tool 100 passes into the lowermost sliding sleeve 50A. Using a upward jarring movement, the upper (opening) tool 100 opens the lowermost sliding sleeve 50A by engaging the collet's B-profiles (122) into the insert's upper recess (58) (See FIG. 6A). A jar (not shown) installed on the continuous rod 40 or the rig (30) at the surface can impart this jarring movement. Once the sleeve 50A opens and the B-profiles (122) cams free, the continuous rod 40 and tools 100/200 are moved below the open lowermost sleeve 50A, as shown in FIG. 7B.

As then shown in FIG. 7B, operators perform a frac treatment by pumping frac fluid down the tool string 14 while the continuous rod 40 remains in the tubing sting 14. Leaving the continuous rod 40 and shifting tools 100/200 in the string 14 during the frac treatment below the open sleeve 50A eliminates the rig time that would be required to trip the tools 100/200 and rod 40 out of the sting 14 between frac treatments, as would conventionally be done to protect coiled tubing if used to actuate the sleeves.

During treatment, the frac fluid diverts through the open sleeve 50A and treats the adjacent isolated zone though the perforations 13. Once this zone has been treated, operators use the rig to lift the continuous rod 40 in the string 14. As shown in FIG. 7C, the upper tool 100 freely passes through the lowermost sliding sleeve 50A that remains open. With further lifting, the lower (closing) tool 200 is positioned to engage this open sliding sleeve 50A. Using a downward jarring movement, the lower tool 200 closes this lowermost sleeve 50A.

As shown in FIG. 7D, the device 60 and rod 40 are then lifted in the tubing string 14, and the upper (opening) tool 100 engages the next uppermost sliding sleeve 50B (which is closed). Using an upward jarring movement, the tool 100 is used to open this sleeve 50B. As shown in FIG. 7E, once the upper tool 100 cams free, operators position the two tools 100/200 in between the sliding sleeves 50A-50B, pump frac fluid in the string 14, and treat the next isolated zone adjacent the open sleeve 50B. Once fracing is complete for this zone, operators lift the tools 100/200 and again close the open sliding sleeve 50B, open the next upper most sliding sleeve 50C, and frac the next zone. Operations then continue in this same manner up the string 14 as each successively higher isolated zone is treated.

Although the frac operation discussed above involved opening the sleeves 50 in the uphole direction and closing them in the downhole direction, the reverse arrangement could be used. Likewise, treatment of successive zones could proceed successively from the uppermost zone to the lowermost zone or could be performed selectively at any of the various zones. In addition, although the device 60 and continuous rod 40 are initially deployed from the surface downhole to the lowermost sleeve 50A in the above discussion, it is also possible to deploy the device 60 independently in a bottomhole assembly (not shown) coupled in a conventional manner to the tubing string 14 below the lower most sliding sleeve 50A. In this case, the continuous rod 40 can then be deployed downhole with a suitable coupling known in the art to connect to the device 60 and retrieve if from the bottomhole assembly to conduct the successive frac operations up the wellbore.

The tool actuating device 60 of FIG. 3 uses upper and lower shifting tools 100 and 200 separated by an intermediate sucker rod 80. Another arrangement of the device 60 can uses a two-way shifting tool 300 as shown in FIGS. 8A-8B. Here, the two-way shifting tool 300 couples to the threaded pin 42 of the continuous rod 40 using a sucker rod coupling 70. The two-way tool 300 includes many of the same components as the upper and lower tools discussed previously so that the tool 300 includes a core mandrel 310, a fishneck coupling 302, stops 312/314, a biased collet 320, and a nose 304. On this tool 300, the collet 320 has dual B-profiles 322 having a downward-facing shoulder 324, an upper cam 326, an upward-facing shoulder 325, and a lower cam 328. Depending on the sleeve's configuration, the shifting tool 300 can open/close the sleeve by jarring down and can close/open the sleeve by jarring up. This tool 300 can be used for selective frac treatments of isolated zones in a similar fashion to that discussed above with reference to FIGS. 7A-7E.

In general, the continuous rod 40 used with the system 10 can be COROD® and can have similar properties and characteristics. (COROD is a registered trademark of Weatherford/Lamb Inc.—the assignee of the present disclosure). For example, the continuous rod 40 can be composed of carbon steel, chromium-molybdenum alloy steel (e.g., AISI 4142), or other suitable material and can have round or semi-elliptical cross-section with a diameter ranging from 12/16-inch to 18/16-inch, for example.

As shown in FIGS. 2A-2B and 6A-6B, the system 10 when used for frac operations can be used with a mono-bore type of sliding sleeve, but other types of sliding sleeves could also be used. Examples of suitable sliding sleeves include the Otimax™ Sliding Sleeve, the Optislim™ Sliding Sleeve, and WXO and WXA Standard Sliding Sleeves, each of which are products of Weatherford/Lamb, Inc.—assignee of the present application.

Although the system 10 has been described for opening and closing sliding sleeves on a frac string, the system of continuous rod 40 and tool actuating device 60 can also be used to actuate other downhole tools that can be actuated to a first operative condition in a first direction and to a second operative condition in a second direction. Some other suitable downhole tools include, for example, a gravel pack closing sleeve, a completion isolation valve, or other downhole tool having shiftable operation. With any of these downhole tools, the ability to actuate the tool with the continuous rod 40 and actuating device 60 can be enhanced by the reliable and efficient operation that the rod 40 and device 60 offer in either vertical or horizontal wells.

The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof.

Claims

1. A downhole tool actuating method, comprising:

installing a first shifting tool to an end of a continuous rod, the first shifting tool adapted to selectively actuate a downhole tool in a first direction to a first operative condition;

installing an intermediate rod below the first shifting tool;

installing a second shifting tool to an end of the intermediate rod, the second shifting tool adapted to selectively actuate a downhole tool in a second direction to a second operative condition;

deploying the continuous rod and the first and second shifting tools downhole to a downhole tool; and

selectively actuating the downhole tool to either the first or the second operative condition by moving the first and second shifting tools with the continuous rod in either the first or second directions relative to the downhole tool to selectively actuate the downhole tool with either the first or second shifting tool.

2. The method of claim 1, wherein the downhole tool is a sliding sleeve having an insert movable between opened and closed conditions.

3. The method of claim 1, wherein installing the first shifting tool to the end of the continuous rod comprises coupling a first threaded pin on the continuous rod to a second threaded pin on the first shifting tool using a sucker rod connector.

4. The method of claim 1, wherein installing the intermediate rod comprises coupling a first threaded pin of a sucker rod to a second threaded pin of the first shifting tool using a sucker rod connector.

5. The method of claim 1, wherein selectively actuating the downhole tool to the first operative condition comprises:

engaging an uphole facing shoulder on the first shifting tool against a downhole facing shoulder on the downhole tool; and

selectively actuating the downhole tool to an opened condition by moving the first shifting tool in an uphole direction.

6. The method of claim 5, wherein selectively actuating the downhole tool to the opened condition further comprises camming the uphole facing shoulder free from the downhole facing shoulder against a first stop shoulder in the downhole tool.

7. The method of claim 5, wherein selectively actuating the downhole tool to the second operative condition comprises:

engaging a downhole facing shoulder on the second shifting tool against an uphole facing shoulder on the downhole tool; and

selectively actuating the downhole tool to a closed condition by moving the second shifting tool in a downhole direction.

8. The method of claim 7, wherein selectively actuating the downhole tool to the closed condition further comprises camming the downhole facing shoulder free from the uphole facing shoulder against a second stop shoulder in the downhole tool.

9. A sliding sleeve actuating method, comprising:

installing at least one shifting tool on an end of a continuous rod, the at least one shifting tool adapted to selectively actuate a downhole tool in a first direction to a first operative condition and in a second direction to a second operative condition;

deploying the continuous rod and the at least one shifting tool downhole to a downhole tool; and

selectively actuating the downhole tool to either the first or second operative condition by moving the at least one shifting tool with the continuous rod in either the first or second directions relative to the downhole tool to selectively actuate the downhole tool with the at least one shifting tool.

10. The method of claim 9, wherein selectively actuating the downhole tool to the first operative condition comprises:

engaging a first shoulder on the at least one shifting tool facing a first direction against a second shoulder on the downhole tool facing a second opposite direction; and

selectively actuating the downhole tool to the first operative condition by moving the at least one shifting tool in the first direction.

11. The method of claim 10, wherein selectively actuating the downhole tool to the first operative condition further comprises camming the first shoulder free from the second shoulder against a first stop shoulder in the downhole tool.

12. The method of claim 10, wherein selectively actuating the downhole tool to the second operative condition comprises:

engaging a second shoulder on the shifting tool facing the second direction against a first shoulder on the downhole tool facing the first opposite direction; and

selectively actuating the downhole tool to the second operative condition by moving the at least one shifting tool in the second direction.

13. The method of claim 12, wherein selectively actuating the downhole tool to the second operative condition further comprises camming the second shoulder free from the first shoulder against a second stop shoulder in the downhole tool.

14. A formation fracing method, comprising:

deploying a continuous rod downhole to a plurality of sliding sleeves, the continuous rod having at least one shifting tool adapted to selectively open and close a sliding sleeve in opposing first and second directions;

selectively opening and closing the sliding sleeves by moving the at least one shifting tool with the continuous rod in the first and second opposing directions relative to the sliding sleeves; and

fracing selective zones of the formation isolated by packers disposed downhole between each of the sliding sleeves by using the at least one shifting tool and the continuous rod to successively open and close the sliding sleeves in the selective zones.

15. The method of claim 14, wherein deploying the continuous rod downhole comprises installing one shifting tool on an end of the continuous rod, the one shifting tool adapted to selectively open the sliding sleeve in the first direction and to selectively close the sliding sleeve in the second direction.

16. The method of claim 14, wherein deploying the continuous rod downhole comprises:

installing a first shifting tool to an end of the continuous rod;

installing an intermediate rod below the first shifting tool; and

installing a second shifting tool to an end of the intermediate rod.

17. The method of claim 16, wherein the first shifting tool is adapted to selectively open the sliding sleeve in the first direction, and wherein the second shifting tool is adapted to selectively close the sliding sleeve in the second direction.

18. A downhole tool actuating system, comprising:

a continuous rod having a distal end;

a surface rig operable to deploy and move the continuous rod in first and second directions downhole; and

a tool actuating device coupleable to the distal end of the continuous rod, the tool actuating device having a first profile adapted to selectively actuate a downhole tool in the first direction to a first operative condition, the tool actuating device having a second profile adapted to selectively actuate the downhole tool in the second direction to a second operative condition.

19. The system of claim 18, wherein the tool actuating device comprises:

a first shifting tool coupleable to the distal end of the continuous rod and having the first profile;

an intermediate rod having first and second ends, the first end coupleable to the first shifting tool; and

a second shifting tool coupleable to the second end of the intermediate rod and having the second profile.

20. The system of claim 18, wherein the tool actuating device comprises a shifting tool coupleable to the distal end of the continuous rod, the shifting tool having the first and second profiles.