You are an expert at summarizing long articles. Proceed to summarize the following text:

You are an expert at summarizing long articles. Proceed to summarize the following text: 
FIELD OF THE INVENTION 
       [0001]    Well casing plugs are configured to allow casing sealing and movement within the casing. The well plug system can be untethered from the surface and can include controllers to sense well conditions and initiate actions, such as opening or creation of hydraulic fracturing ports. Methods include steps for the system to seal a well casing, open ports through the well casing, and relocation of the system within a well casing. 
       BACKGROUND OF THE INVENTION 
       [0002]    Systems exist to plug a well casing. This can be, e.g., to prevent escape of pressurized fluids to the surface, as a support for sealing an exhausted well, or to seal a region of a well to be stimulated by hydraulic fracturing. 
         [0003]    In one example, Inflatable Flowing Hole Plug, to Christensen (U.S. Pat. No. 4,449,584), a pair of inflatable plugs are lowered on a conduit to a well location needing to be sealed from other flows. Once located at the desired position, the plugs are reversibly inflated to prevent movement of fluids past the plug location. The system must receive power from the surface and must be positioned based on the length of the suspension conduit. 
         [0004]    In Naedler, Disintegrating Ball for sealing Frac Plug Set (U.S. 2012/0181032), a ball and seat valve includes a ball that dissolves over time on exposure to hydrocarbons in a well casing. The valve body can be threadably sealed into a well casing and receive proximal pressures intended for hydraulic fracturing. The ball prevents the hydraulic pressures from passing distally and the fluids move instead through casing holes to fracture adjacent formations. As the ball eventually dissolves, fluids (e.g., crude oil from distal locations) can pass freely past the valve. The system requires preinstallation in the casing and is single use. 
         [0005]    In Bloom, Gripper Assembly for Downhole Tools (U.S. Pat. No. 8,944,161), an assembly can be inserted down a well and anchored at a location by extending shoulders out from the assembly to contact the interior well casing wall. The grippers are urged out by the action of rollers pushing a cam out against the gripper. Further, Bloom describes a crawling motion in which proximal and distal grippers are alternately bound and releast at the casing wall while the body of the assembly changes in length, providing a crawling motion. The assembly is designed to exert forces to tools down hole and must be tethered to the surface to function. 
         [0006]    In view of the above, a need exists for a system that is repositionable and reusable, e.g., so that multiple hydraulic fracturing operations can be performed without preinstallation of equipment in the casing, or having to insert wireline-based tools between hydraulic fracturing well stimulation operations. We see that it would be desirable to have independent equipment that can seal well casings at multiple locations over time. Benefits could also be realized through systems that can work independently while other processes are ongoing in adjacent wells. The present invention provides these and other features that will be apparent upon review of the following. 
       SUMMARY OF THE INVENTION 
       [0007]    The present inventions include systems and methods that provide flexibility and independence for operations of working systems within a wellbore. The systems include controllable sealing and tractor mechanisms that allow selection of sealing locations. Further, the systems can have complementary tools that facilitate down hole operations. For example, the systems can have mechanisms to rigidly retain the plug at a location, in the face of intense pressures experienced in hydraulic fracturing operations. Sub-systems can include reversibly actuated seals, gripper features, tractor features, length extension features, and tools to open or create ports through the casing. The systems can include communication systems, sensor systems, and logic systems that allow independent or semi-independent operations without continuous interaction with the surface. 
         [0008]    Exemplary methods that employ features of the well casing plug systems can include actions to carry out repeated fracturing operations at multiple locations. For example, a mobile well plug system can be lowered and released into a well bore. At a desired location, a distal expandable seal can be actuated to seal the plug at the location. To further brace the system against pressures in the casing, grippers can be extended out to contact the well casing. Pyrotechnics carried by the system can be fired to perforate holes through the casing. Frac fluids and proppant can be introduced at high pressures to flow through the holes thus created and out the holes to fracture the local formations. The seal and grippers can be released and a tractor device extended in contact with the inside casing wall to transport the system to a new desired location within the well casing, e.g., to perform additional fracturing processes. 
         [0009]    The present invention solves several problems we have identified in the prior art. The present self-contained multi-state well plug embodiments include repositionable elements which relocate, seal, and unseal to serve as a plug for a series of frac (hydraulic fracturing) stages along one wellbore or a set of interconnected wellbores. In one embodiment, the present invention incorporates casing perforation capability. The present invention is useful for stimulation of onshore wells, deepwater wells, and ultra deepwater wells. Alternately, the systems may be used in other applications. The present invention can incorporate electronics, energy storage devices, and actuators in one or more mobile downhole tools, rather than in permanent downhole components, thus reducing costs. Alternately, sensors may be placed on casing segments to acquire well flow and other data over time. In another aspect of the invention, electromagnetically induced signals are transmitted along the well casing to communicate with the repositionable plug and other components while they are downhole. 
         [0010]    The present invention has several major advantages over the prior art. The present invention is intended to reduce well completion costs and increase well production. One major advantage of the present invention over the prior art is that the present invention does not leave complex mechanisms downhole during cementing operations, thereby avoiding potential cement residue that may impair future operation. 
         [0011]    Since the repositionable plug is repositioned for each frac stage and retrieved from the well after stimulation, it eliminates the costly and time consuming process of milling the frac plugs to remove them after the well stimulation is completed. Thus, well completion costs are reduced and the well is in production mode more rapidly, thereby reducing formation damage. 
         [0012]    In addition, the present invention minimizes costly and time consuming trips downhole during the well completion process. A single downhole trip preferably by a wireline-connected deployment tool is needed to place the repositionable plug. A second downhole trip preferably by a wireline-connected retrieval tool is needed to retrieve the repositionable plug. Optionally, sleeves may be placed in the well casing before it is inserted into the wellbore. Each frac stage may be tested in situ and individually optimized to increase the production yield from each stage. The present invention does not require the use of expensive coiled tubing for fracing the well nor for milling out the plugs after well stimulation. The preferably untethered repositionable plug allows for an unlimited number of frac stages per well. The repositionable bore plug is compatible with horizontal, vertical, or inclined wellbores. 
         [0013]    Prior art inventions (e.g., Naedler—U.S. 2012/0181032, above) use dissolvable frac plugs which typically dissolve over a time period ranging from two to five days to allow hydrocarbon production from the well. Dissolving plugs can reduce the time to production and reduce cost as compared to the time required post frac to mill out non-dissolvable frac plugs. However, this old art procedure can significantly increase the likelihood of undesirable residual proppant (e.g., sand) packing in the wellbore proximal to the dissolved plugs substantially reducing flow from the well even after the frac plugs dissolve. Advantageously, the present invention allows immediate removal of the plug from the well after fracing, avoiding the residual proppant packing problem. 
         [0014]    An aspect of the invention includes systems for repositioning a well plug. For example, a down hole plug system for sequential fracking along a well casing can include a seal and means to reposition the plug in a well casing. The system can include a plug body, an expandable seal mounted on the body and adapted to expand and reversibly seal the body in a well casing, and one or more first casing grips mounted to the body and adapted to extend out from the body and engage the well casing, thereby fixing the plug at a location in the well casing. The seal can be resilient and have a fluid inlet to receive a fluid under pressure, so that a pressurized fluid can expand the seal to contact the well case forming a hydraulic seal. The casing grips can have grip teeth directed away from a body axis. The casing grips can be mounted to the body on a pivot with the grip teeth adapted to grip the well casing when the grips are forced out radially from the body. In one embodiment, the grips are forced out radially by a cam and roller system in the body. Optionally, the well casing, or a coupling between well casing segments, can have an internal ridge so that the grips can extend to contact the ridge, providing structural support and preventing the plug from moving past the ridge. 
         [0015]    The well plug can be repositioned, e.g., by alternately gripping and releasing, e.g., with proximal and distal grips, in association with changes in length of the plug body, so that the system crawls along the well, for example, the system can further comprise one or more distal grips distal to the first proximal grips, and one or more extension means (e.g, extension cylinders, rack/pinion, threaded rod, etc.) between the proximal and distal grips, whereby the distance between the proximal grips and distal grips can be increased and/or decreased. Such crawling can be accomplished within the well casting, e.g., by first gripping with a proximal or distal grip, increasing the distance between the proximal and distal grips, releasing the first gripping proximal or distal grip, second gripping with an alternate grip not used in the first gripping, and reducing or increasing the distance between the proximal and distal grips by increasing or decreasing a length of the one or more extension cylinders. 
         [0016]    In another embodiment of down hole plug systems for sequential frac processes along a well casing, the plug can be repositioned using one or more drive wheels. For example, the plug system can include a plug body, an expandable seal mounted around the body and adapted to expand and reversibly seal the body in a well casing, one or more drive wheels mounted to the body and extendable out from the body to engage the well casing, and a source of power to turn the one or more drive wheels, thereby moving the plug system along the well casing. The drive wheels can be extendable using a drive piston, e.g., and be powered by a motor in the plug body. The system can include one or more idler wheels mounted to the plug body and acting to space the plug body away from the well casing and to urge the drive wheel against the inside of the well casing for traction. The drive wheel embodiment can also include one or more casing grips mounted to the body and adapted to extend out from the body and engage the well casing, thereby fixing the plug at a location in the well casing, e.g., during casing piercing or fracking operations. 
         [0017]    The systems above can include additional features. For example, the systems can include features and ways to direct pressurized fluids into the environment around the well casing, e.g., to facilitate fracturing or well stimulation in oil and gas extraction. For example, the plug body, or associated device, can include a means of perforating the well casing. This casing perforation could involve chiseling, drilling, abrasion, etc., but in a preferred embodiment pyrotechnics are involved. Optionally, the system can be positioned into a well segment having one or more frac ports, e.g., preplaced to provide access to the external well casing. For example, the casing can include a port slide movable to alternately open or close the frac port. Optionally, the plug system is untethered to the surface. 
         [0018]    The system can include a controller (e.g., a digital computer) and one or more actuators (e.g., motors) configured to energize movement of features, such as, e.g., a proximal grip, a distal grip, an expandable seal, an extension cylinder, and/or the like. The controller can be preprogrammed or adapted to receive instructions from the surface while the plug system is down hole. The controller can be in communication to receive inputs from one or more sensors (e.g., pressure, temperature, pH, etc.) mounted in the plug body. 
         [0019]    The present inventions include methods of repositioning a system within a well casing, and methods of well stimulation such as hydraulic fracturing (fracturing). In one method of fracturing a well at multiple locations, a well casing plug is provided comprising a plug body comprising a proximal end and a distal end, an expandable seal mounted on the body and adapted to expand and reversibly seal the body in a well casing. A propelling device is mounted to the plug body to contact the inside of the well casing and move the plug body along the well casing. The plug body can be sealed (preventing fluids to flow past the position of the plug body in the well casing), e.g., by an expandable seal against the well casing. A port or perforation can be opened through the well casing and the inside of the well casing is pressurized, e.g., so fluids flow through the opening, exposing the outside environment to fracturing pressures. With fracturing complete, the seal can be unsealed from the well casing, freeing the plug body for repositioning. Using a propelling device (e.g., grips or drive wheels) the plug can be moved to a different location within the well casing. By repeating these steps, the plug body can complete fracturing at one location, then move on to another location for additional fracturing. 
         [0020]    Repositioning and fracturing with the well plug system can be by any appropriate means, For example, the system can use a propelling means described herein, e.g., such as a drive wheel or a grip/expansion cylinder combination. The system can gain access to the environment outside the well casing, e.g., by opening a port prepositioned in the well casing or by opening a perforation by use of pyrotechnic charges. 
         [0021]    A preferred embodiment of the repositionable frac plug uses pyrotechnic charges to perforate the casing in combination with one or more repositionable plugs and a deployment and retrieval tool (referred to herein as the “DR tool”). This embodiment can use casing joints with ridges on the inside diameter to axially register and structurally support the repositionable well plug. The perforating charge embodiment does not require port slides in the well casing. Pyrotechnic charges are preferably attached to the repositionable plug. They may be positioned axially, rotated angularly, and fired sequentially by the repositionable well plug at the proper location for each frac stage. Alternately, pyrotechnic charges may be incorporated in conventional pyrotechnic perforation guns inserted from the wellhead while the repositionable plug remains in the wellbore. 
         [0022]    Another embodiment of the system uses movable port slides in the wall of a well casing segment as shown in  FIG. 19  and  FIG. 20  in combination with one or more repositionable plugs and a DR tool. The movable port slides operate by sliding axially along the casing segment to expose ports in the casing wall. 
         [0023]    In a further embodiment of the present invention casing grips are used on the repositionable plug to grip the inside diameter of the casing, locking the plug into position for a frac stage, thereby eliminating the need for the flanged casing joints. 
         [0024]    Testing of each stage prior to fracing may be accomplished by observing flow as a function of pressure or temperature for a specific frac stage and by measuring differential pressure, differential temperature, or other parameters. The measurement of these data may allow inference of the well production characteristics at or near that specific location. Using this information, frac parameters, such as flow rate, pressure, proppant type and density, and/or stage duration, may be optimized for localized shale conditions at or near that frac stage. Additionally, thief zones in the shale, which can decrease well production, may be identified and avoided through identification of patterns in the observed well data. Each frac stage may be tested prior to fracing with lower pressure, reduced proppant, and/or lower fluid flow than required to stimulate the stage, to determine if the stage is likely to be highly productive. If data indicates that the stage is expected to have low production, the frac (stimulation) for that stage may be skipped and the movable plug may be repositioned at the location of the next frac stage. Frac stages may be more optimally spaced by locating frac stages closer together in high production zones of the well, and by avoiding well locations which may drain production due to faults or other features in the shale. Additionally, more extensive frac treatments may be provided in highly productive zones of the well. 
         [0025]    As with the inventions of the parent application, the present invention enables immediate production from the well, thus increasing the overall hydrocarbon output of the well by reducing formation damage. After fracing, a well placed into immediate production can have substantially increased production for the life of the well if properly choked. Production can increase by as much as 30% or more while potentially reducing completion costs from shale oil and gas wells and other types of wells. Thus, the present invention may increase production of hydrocarbons per well due to a) the ability to get the well in production sooner due to not needing to mill out the bridge plugs, b) the optimization of the frac parameters for each well stage, and c) the ability to skip marginally productive or thief zones. 
         [0026]    In a preferred embodiment of the present invention, casing perforation charges are incorporated into the repositionable plug. This embodiment has the further advantage of accommodating variable length frac stages even if the well casing was not fully inserted into the drilled wellbore. This embodiment further allows different types of pyrotechnic charges to be optimally used for different shale condition at different frac stages along the well length. For example, pyrotechnic charges may be optimized for different shale permeabilities. The pyrotechnic charges on the repositionable plug may be rotated into optimal orientation with respect to the plane of the shale layer. The perforation charges may advantageously be optimized in quantity, type, and spacing for the geology and expected production at each frac stage. 
         [0027]    The repositionable plug can be configured to evenly distribute the weight of the plug over the length of the plug. The repositionable plug is preferably corrosion resistant to enable it to be employed even when hydrochloric acid is pumped downhole to treat the formation prior to fracing or to treat carbonate reservoirs. The repositionable plug is easily serviced after removal from the well. In the rare event of a failure, the repositionable plug is preferably designed to fail in an easily retrievable state. Optional sliding sleeves in the well casing are preferably corrosion resistant and therefore may be left downhole for years after the casing is completed but before the well is fraced. 
       DEFINITIONS 
       [0028]    Before describing the present invention in detail, it is to be understood that this invention is not limited to particular devices, which can, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting. As used in this specification and the appended claims, the singular forms “a”, “an” and “the” include plural referents unless the content clearly dictates otherwise. Thus, for example, reference to “a surface” includes a combination of two or more surfaces; reference to “proppant” includes mixtures of proppant, and the like. 
         [0029]    Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which the invention pertains. Although any methods and materials similar or equivalent to those described herein can be practiced without undue experimentation based on the present disclosure, preferred materials and methods are described herein. In describing and claiming the present invention, the following terminology will be used in accordance with the definitions set out below. 
         [0030]    As used herein “fracing” or hydraulic fracturing is a well-stimulation technique in which rock in the well is fractured by a pressurized liquid. 
         [0031]    As used herein a well casing is as known in the art of hydrocarbon exploration or water well drilling. For example, an oil well casing is typically the pipe that is assembled and inserted into a recently drilled section of a borehole. Although other pipes and strings may be inserted into the well hole, the casing is the inner most pipe down hole. 
         [0032]    As used herein, a “plug” is a device that functions to seal a pipe, such as a well casing, against flow of fluids therethrough. An expandable plug is configured to expand radially to come in contact and seal against the inside wall of a pipe, such as a well casing. A reversibly sealable plug may be adapted to, (e.g., alternately be expanded to) contact and seal a pipe, then contracted to release the seal. 
         [0033]    As used herein, directions are as commonly used. For example. up is opposite the force of gravity on earth. In the context of a well bore, axially is along the center axis of the bore, radially is out away from the axis, e.g., perpendicular to the axis. Proximal is toward the end of the bore where the drill or casing was inserted (typically closer to the earth&#39;s surface) and distally is in the direction in which drilling progressed (e.g., away from the earth&#39;s surface). Down hole refers to the well below grade level. 
         [0034]    As used herein, a controller is a, digital processor, as known in the art. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0035]      FIG. 1  is a perspective view of the repositionable plug. 
           [0036]      FIG. 2  is a perspective view of the repositionable plug without housing. 
           [0037]      FIG. 3  is a cross-sectional perspective view of the distal end of the repositionable pug. 
           [0038]      FIG. 4  is a Cross-Sectional Perspective View of the Distal End of the Repositionable Plug with Ram Extended. 
           [0039]      FIG. 5  is a Cross-Sectional Perspective View of the Distal Cam Piston Subassembly with casing grips retracted. 
           [0040]      FIG. 6  is a Cross-Sectional Perspective View of the Distal Cam Piston Subassembly with casing grips extended. 
           [0041]      FIG. 7  is a Cross-Sectional Perspective View of the Proximal Cam Piston Subassembly. 
           [0042]      FIG. 8  is a Cross-Sectional Perspective View of the Proximal Cam Piston Subassembly with casing grips extended. 
           [0043]      FIG. 9  is a Cross-Sectional Perspective View of the Proximal Cam Piston Subassembly with casing grips and seal extended. 
           [0044]      FIG. 10  is a Perspective View of the Preferred Proximal and Distal Casing Grip. 
           [0045]      FIG. 11  is a Perspective View of the Alternate Proximal Casing Grip. 
           [0046]      FIG. 12  is a Cross-Sectional Perspective View of a Repositionable Plug Center Section. 
           [0047]      FIG. 13  is a Cross-Sectional Perspective View of the Proximal Center of Repositionable Plug. 
           [0048]      FIG. 14  is a Diagram of the Hydraulic Circuit. 
           [0049]      FIG. 15  is a Cross-Sectional Perspective View of the Extraction Tool Engaged with the Repositionable Plug. 
           [0050]      FIG. 16  is a Perspective View of the Proximal End of the Repositionable Plug with Perforators. 
           [0051]      FIG. 17  is a Cross-Sectional Perspective View of the Repositionable Plug Tractor Drive Subassembly. 
           [0052]      FIG. 18  is a Cross-Sectional Perspective View of the Repositionable Plug Drive Piston. 
           [0053]      FIG. 19  is a Cross-Sectional Perspective View of a Casing Segment with the Port Slide in the Closed Position without the Plug. 
           [0054]      FIG. 20  is a Cross-Sectional Perspective View of a Casing Segment with the Port Slide in the Open Position without the Plug. 
           [0055]      FIG. 21  is a Diagram of the Control System. 
           [0056]      FIG. 22  is a Cross-Sectional Perspective View of the Extraction Tool. 
           [0057]      FIG. 23  is a Cross-Sectional Perspective View of the Casing Coupling with Casing Joints. 
       
    
    
     DETAILED DESCRIPTION 
       [0058]    One embodiment of the present invention is repositionable plug  10  shown in  FIG. 1 . The preferably cylindrical body  11  of repositionable plug  10  has a preferably tapered distal end  12  with a plurality of distal casing grips  13 . The proximal end of plug  10  preferably has a plurality of proximal casing grips  14  and a sensor cavity  16  preferably proximal to elastomeric seal  9 . The body of plug  10  is preferably smaller than the inside diameter of the well casing and short enough to pass through curved sections of well casing and imperfections such as doglegs and partially collapsed sections without interference. Plug  10  may optionally contain one or more movable joints to make it flexible enough to pass through, if required. Repositionable plug  10  shell is preferably fabricated of steel alloy, titanium alloy, composite, ceramic, and/or other suitable material. 
         [0059]    Each repositionable plug  10  accommodates a predetermined range of casing inside diameters. For example, an 8.57 cm (3.375 in) outside diameter repositionable plug is suitable for a 14 cm (5.5 in) outside diameter 20 lb/ft well casing having a 12.11 cm (4.77 in) inside diameter or a 17 lb/ft well casing, or a 23 lb/ft well casing. Repositionable plug  10  preferably has a maximum retracted length less than 5 m (16 feet) and preferably has a diameter of 8.57 cm (3.375 in) or less to enable it to pass through problem areas in the well casing during insertion and extraction from the well. The small diameter of plug  10  allows ease of movement through a 90 degree radiused bend in the well casing connecting the vertical portion of a shale well to the horizontal portion of the well. Optionally, incorporating articulated joints along plug  10  length may increase plug  10  length. Smaller diameter versions of plug  10  may be designed for use in smaller diameter casings used for ultra deepwater wells. Alternately, another suitable length and diameter may be chosen. 
         [0060]    An impact-absorbing bumper is preferably located on the distal end of plug  10  to protect against collision with the bottom hole assembly or other object. An impact-absorbing bumper may additionally be placed on the proximal end of plug  10  to absorb impact from collisions with the extraction tool or other downhole tools. 
         [0061]    Sensor cavity  16  preferably includes one or more pressure sensors configured to measure absolute pressure in the wellbore and to receive pressure pulse signals through the wellbore. Sensor cavity  16  is preferably located proximal to elastomeric seal  9  to prevent pressure signal attenuation when seal  9  when is expanded. Additional pressure sensors may be configured to obtain static and dynamic pressure measurements. Sensor cavity  16  can contain one or more thermal sensors such as thermocouples or thermistors. Additional thermal sensors may be located at the distal end of plug  10  to obtain differential temperature measurements. 
         [0062]    Sensor cavity  16  preferably houses radially sensing hall effect sensors or other sensors configured to detect the axial position of casing couplings with respect to ridges  15  or other well casing features or to detect couplings between sections of well casing. Sections of well casing are commonly referred to as “joints.” The Hall effect sensors may also be used to detect burrs on the casing inside diameter resulting from pyrotechnic perforations. Alternately, ultrasonic or other sensors can be used. Optionally, sensor cavity  16  or other locations on plug  10  may contain a coil or other sensor for receiving electromagnetic induction signals transmitted along the well casing from the wellhead or from the deployment and retrieval tool or from other components or downhole tools. Optionally, sensor cavity  16  or other locations on plug  10  may contain an induction coil transmitter for transmitting status signals and other data from plug  10  to the wellhead or to other downhole tools. Sensor cavity  16  is preferably sealed with O-rings or other sealing elements to prevent intrusion of fluids from the well bore. Sensor housing  16  may be fabricated from non-magnetic material to enhance the sensitivity of the Hall sensors. In addition, magnetic susceptors may be used to increase Hall effect sensor sensitivity. Alternately, other materials or sensor types may be used. Proximal tip  81  of plug  10  may further include a magnet or other means to provide a proximity signal to DR tool. Proximal tip  81  may further contain an energy absorbing bumper element. 
         [0063]    In a preferred embodiment of the invention, perforation guns may be attached to plug  10  to eliminate the need for additional downhole trips to perforate the casing between frac stages. Multiple sets of perforation charges to enable multiple stages to be perforated may be attached to plug  10 .  FIG. 16  shows multiple perforation guns  163  attached to the proximal end of plug  10  distal to helix  80  and proximal to sensor cavity  16 , seal  9 , and other parts of plug  10 . Perforation charges  161  are shown helically arranged for each stage on perforation guns in  FIG. 16 . Alternately, perforation guns  163  may located on the distal end of plug  10  or at any other suitable location. U-joint  162  shown in  FIG. 16  allows the entire plug  10  system to articulate to pass through radii or doglegs or other imperfections or tight locations in the casing. Multiple U-joints may be used if required. 
         [0064]      FIG. 2  shows the embodiment of repositionable plug  10  from  FIG. 1  with the outer shell removed. Outer shell  11  (body) is designed to provide structural integrity during operation and to prevent fluid intrusion from high downhole pressures. Repositionable plug  10  preferably has a distal valve body  20  that preferably contains at least two hydraulic solenoid valves and a proximal valve body  21 , which preferably has at least one hydraulic solenoid valve. The hydraulic solenoid valves are preferably low resistance three-way valves. A spring return design of each hydraulic cylinder allows simple three-way valves to be used. Alternately, servo valves may be used. Alternately, another type of valve may be used. Hydraulic reservoir  22  is suitably located within plug  10 . Hydraulic reservoir  22  may be located at any suitable location, including at least partially in the interstitial spaces of the batteries  17 . High temperature hydraulic fluid such as a phosphate ester based hydraulic fluid, for example Exxon HyJet V, is preferably used as the working fluid in the hydraulic system. Alternately, any other suitable hydraulic fluid may be used. Alternately, mechanical actuators or others means are used instead of the hydraulic system. 
         [0065]    Motor  18  is preferably a brushless DC motor equipped with multiple hall effect sensors for use in controlling its angular position, rotational speed, and current through monitoring its rotational position and velocity. Motor  18  preferably has temperature sensors to enable monitoring of motor temperature to prevent overheating. Alternately, another type of motor is used. Alternately, another means is used to drive hydraulic pump  19 . Motor  18  is preferably immersed in a heat dispersing fluid or gas to assist in cooling to enable greater output power. Possible cooling fluids include fluorocarbon fluids such as perflourohexane, perflouro methyl cyclohexane, perflouro 1,3 methylcyclohexane, perflouro decalin, and perflouro methyl decalin. Alternately, oil, hydraulic fluid, or other fluid may be used. Sealed conduits between bulkheads may pass cables and hydraulic lines through the motor section of the casing while isolating the motor cooling fluid. 
         [0066]    An array of batteries  17  preferably powers motor  18  through a suitable multi-phase H-bridge amplifier or other smart servo drive method commonly known to those skilled in the art. The servo drive is preferably controlled via a pulse width modulated signal supplied by the microcontroller described below. Alternately, current to motor  18  may be switched directly from batteries  17  or from another source. Alternately, a mud motor or other power source may be used. Motor  18  preferably drives hydraulic pump  19  though a planetary gearbox or other type of gearbox to provide optimal torque and speed. A multiple speed gearbox may be used if desired. 
         [0067]    Hydraulic pump  19  is suitably plumbed to provide proper pressure and flow to both the proximal and distal valve bodies. Hydraulic pump  19  is sized to provide fluid power to four spring return pistons controlled by the proximal valve body  21  and distal valve body  20  including extension cylinder  32  as shown in  FIG. 4 , distal cam piston  45  as shown in  FIG. 5  and  FIG. 6 , proximal cam piston  77  and elastomeric seal piston  76  as shown in  FIG. 7 . All piston springs are preferably preloaded, with tension urging the associated piston axially. Pump  19  is also capable of powering other fluid powered elements as needed. Alternately, double acting cylinders may be used. Alternately, another type of drive system such as a motor driven mechanical system may be used. 
         [0068]    The volume of hydraulic fluid pumped by pump  19  is monitored by tracking pump rotations computed from motor  18  hall sensor signals and by monitoring fluid temperature to infer displacement of pistons. Alternately, piston displacement may be measured directly through encoders or other means. Pressures from proximal and distal pressure sensors can also determine pressures in the piston cylinders, from which piston displacements and grip and seal forces may be computed since all pistons have pre-loaded return springs with known spring constants. Alternately, another method or direct measurement by displacement transducers may be used. 
         [0069]    Batteries  17  preferably have sufficient capacity to be used to frac one or more wells. Alternately, battery capacity may allow for less than one well to be fraced, requiring multiple repositionable plugs  10  to be used sequentially for each well or requiring batteries  17  to be replaced between frac stages. Careful programming of repositionable plug  10  can optimize battery life, for example by only partially closing the distal grips  13  during repositioning of the repositionable plug  10  to reduce power requirements. 
         [0070]      FIG. 3  shows a cross-sectional view of the distal end of repositionable plug  10  with extension cylinder  32  retracted and distal cam piston  45  and distal grips  13  retracted. Flexible hydraulic hose  30  directs fluid through the central bore in extension cylinder  32  to transfer fluid to distal cam cylinder  48 , urging distal cam piston  45  to extend distal casing grips  13 . Since flexible hose  30  has minimal volume change despite the large displacement of extension cylinder  32 , extension cylinder  32  motion is effectively decoupled from distal grip  13  motion, enabling grips  13  to maintain proper clamping force against the casing wall even as extension cylinder  32  moves. This design eliminates the need to expend energy to actuate the distal hydraulic solenoid valve to maintain proper pressure in distal cam cylinder  48  during extension cylinder  32  motion. Alternately, another type of fluid transfer conduit is used. Alternately, another means of fluid transfer to the distal end of plug  10  may be used. Optionally, a conduit for distal sensor cables may traverse the center of extension cylinder  32 . 
         [0071]    As extension cylinder  32  extends, increased hydraulic pressure is required due to the increasing force needed to compress the return spring  49  as shown in  FIG. 2  and  FIG. 3 . Added to this force is the force needed to push plug  10  through the proppant pack remaining in the well bore after the previous frac stage, since the wellbore may be packed with proppant and gel for up to several meters proximal to plug  10  after each frac stage is completed. 
         [0072]    Hydraulic fluid accumulates in reservoir  22 , which is comprised in part by outer shell  11 . Alternately, fluid reservoir  22  may be completely separate from the outer shell. Compression spring  25  exerts force on piston  23  as shown in  FIG. 3  to maintain sufficient pressure on the hydraulic fluid in reservoir  22  to keep reservoir  22  free of air or other gases or fluids independent of the orientation of plug  10 . Alternately, a bladder may be used to maintain pressure in the reservoir. Coaxial tubes  24  pass through fluid reservoir  22  to direct hydraulic fluid to and from distal cam cylinder  48  and extension cylinder  32 . Alternately, tubes may be used that route around a discrete reservoir. 
         [0073]      FIG. 4  shows extension cylinder  32  fully extended with distal cam piston  45  retracted. Hydraulic fluid is pumped into extension cylinder cavity  34  to urge the extension cylinder to extend. Tube  33  inside cylinder  32  is needed to contain the hydraulic fluid and to prevent fluid from escaping into cylinder  32  inner cavity, which houses flexible hydraulic hose  30 . 
         [0074]    Distal cam piston  45  is displaced by hydraulic pressure in cylinder cavity  48  as shown in  FIG. 6  to extend distal grip  13 . Distal cam piston  45  preferably has a pocket for each distal casing grip  13  enabling distal casing grips  13  to retract for wellbore insertion, wellbore extraction, and movement between frac stage positions. Repositionable plug  10  preferably has at least three proximal grips  14  and at least three distal grips  13 . Preferably, each set of proximal grips  14  or distal grips  13  are radially arranged and each set is preferably driven with a single cam piston. Alternately, plug  10  has at least one proximal grip  14  and at least one distal grip  13 . Alternately, more than one cam piston may be used per grip set. A roller cam follower  47  is preferably used on both the proximal and distal cam pistons  77  and  45  to reduce friction and reduce cam wear due to the presence of abrasive proppant downhole. 
         [0075]      FIG. 5  shows distal cam piston  45  with distal grip  13  in the retracted position. As hydraulic pressure in piston cavity  48  creates force on distal cam piston  45  greater than return spring  44  preload force, spring  44  compresses, causing distal cam piston  45  to move distally and forcing roller cam follower  47  to climb cam  42 . The steeply inclined ramp portion  42  of cam piston  45  reduces the axial travel required for distal cam piston  45  to deploy and retract distal grip  13  from the storage pocket in the cam piston. Preferably, the angle of the steep ramp portion is 25 to 35 degrees with respect to the piston axis. Alternately, any other suitable angle may be used. The shallow ramp angle on the further deployment portion  43  of distal cam piston  45  enables distal casing grips  13  to engage with a predetermined range of casing diameters and to accommodate the presence of foreign material in the wellbore. Preferably, the angle of the shallow ramp portion is 1.5 to 3.5 degrees with respect to the piston axis. Alternately, any other suitable angle may be used. When extended through sufficient hydraulic pressure exerted in piston cavity  48 , distal casing grips  13  grip the inside diameter (ID) of the well casing. The thicker cross-section of the cam piston which cam followers  47  roll upon when grips  13  are on shallow ramp portion  43  of the cam while contacting the well casing ID is sized to withstand the higher forces exerted from cam roller  47  onto the cam while casing grips  13  are exerting force on the casing wall. Alternately, other cam angles or profiles may be used. In the preferred embodiment, distal casing grips  13  are cantilevered from roller cam follower  47  as shown in  FIG. 5  and  FIG. 6  to maximize radial travel of grips  13  from the limited radial motion possible with distal cam piston  45 . 
         [0076]    Leaf spring  40  as shown in  FIG. 5  exerts force radially inward to maintain roller cam follower  47  contact with its respective cam path on cam piston  45 . Leaf spring  40  retracts grip  13  into the pocket in cam piston  45  as return spring  44  urges piston  45  to return to its fully retracted position as hydraulic pressure in cylinder  48  is relieved by the three-way valve. Proximal and distal seal protectors  73  and  74  on the outer circumference of plug  10  housing as shown in  FIG. 7  prevent damage to seal  9  from abrasion or impact with casing during insertion extraction or movement between stages of the well. Similarly, distal and proximal grip protectors  3  and  4  prevent damage to distal and proximal casing grips  13  and  14  from abrasion and impact with the well casing. 
         [0077]      FIG. 6  shows distal cam piston  45  displacing distal casing grip  13  to a typical position for contacting the inner casing wall. The annular well casing and leaf spring  40  are not shown in  FIG. 6  for clarity. Preferably, distal grips  13  apply sufficient force to the well casing ID to prevent slippage as plug  10  moves along the well bore. Optionally, distal grips  13  may assist proximal grips  14  in resisting the axial force created by high proximal well pressure. During the frac, well pressures may range from 35,000 kPa to 170,000 kPa (5000 psi to 25,000 psi). Alternately, lower or higher pressures may be used. 
         [0078]    As Grip  13  teeth hold axial location by pressing against the casing ID, plug  10  body moves proximally along the well as extension cylinder  32  extends. Extension cylinder  32  preferably generates sufficient force to push plug  10  through residual proppant and gelling agent in the well bore which is usually found proximal to the plug after the frac stage is completed. The residual proppant and gelling agent in the well bore proximal to the plug after the frac stage is completed is commonly referred to as the “proppant pack.” Consolidated wet 20/40 mesh Ottawa white sand proppant commonly used in fracs has static shear strength of approximately 350 kPa (50 psi), which must be exceeded to initiate motion through the proppant pack. Consolidated wet 20/40 mesh Ottawa white sand proppant has a kinetic shear stress of 180 kPa (25 psi), which must be exceeded to maintain motion through the proppant pack. Both the proximal grips  14  and distal grips  13  preferably have teeth fabricated from titanium alloy, zirconium alloy, high strength steel alloy, maraging steel, ceramic, metal-matrix composite, other high strength alloy, or any other suitable material. Optionally, the teeth on the grips may be removably mounted to the grips. The grip body may be fabricated of a different material than the grip teeth. 
         [0079]    The spring return design of proximal cam piston  77  and distal cam piston  45  enable these pistons to partially retract proximal grips  14  and distal grips  13  between frac stages without requiring servo valves or double acting cam cylinders, thus simplifying the system. In case of hydraulic system failure, the piston return springs exert force to retract extension cylinder  32 , proximal grips  14  and distal grips  13  and seal expansion piston  76  to allow plug  10  to be retrieved from the wellbore by the retrieval tool. 
         [0080]      FIG. 7  and  FIG. 8  show an embodiment of proximal grips  14  and their actuation subsystem similar to the embodiment of distal grips  13  and their respective actuation subsystem described above. Proximal cam piston  77  is displaced by hydraulic pressure in cylinder cavity  86 , as shown in  FIG. 8  to extend proximal grips  14 . Proximal cam piston  77  preferably has a cavity for each proximal casing grip  14  to allow proximal casing grips  14  to retract for well insertion, well extraction, and movement between frac stage positions in the well.  FIG. 7  shows proximal cam piston  77  with proximal grip  14  in the retracted position. 
         [0081]    As hydraulic pressure acting upon proximal cam piston  77  creates sufficient force on proximal cam piston  77  to exceed spring  72  preload force, spring  72  compresses, urging proximal cam piston  77  to move distally and forcing the roller cam follower to roll up the incline on proximal cam piston  77 . As proximal grips  14  are thus urged radially outward, proximal casing grips  14  exert outward force on the ID of the well casing, thus locking casing grips  14  to the well casing. Meanwhile, leaf spring  71  exerts a lesser radial force inward to maintain the roller cam follower contact with the cam path on its respective cam piston.  FIG. 8  shows proximal cam piston  77  displacing proximal casing grip  14  to a typical position for contacting the inner casing wall. The annular well casing and its corresponding leaf spring are not shown in  FIG. 8  for clarity. 
         [0082]    The leaf spring retracts grip  14  back into cam cavity as return spring  72  urges piston  77  to move back to its fully retracted position as hydraulic pressure in cylinder  86  is relieved by the three-way valve. Leaf spring  71  is captured in groove  105  in grip  14  as shown in  FIG. 10  and centered by a slot in the leaf spring to maintain lateral registration of grip  14  in piston cam slot by notch  106 . Roller the cam follower rotates on a pin in bore  104  in casing grip  14 . The cam follower returns to the pocket in cam piston  77  when cam piston  77  is fully retracted. 
         [0083]    As plug  10  moves along the wellbore between frac stages, proximal grips  14  preferably grip the well casing ID with sufficient force to hold plug  10  stationary while extension cylinder  32  retracts. When fluid and proppant are injected into the wellbore during the frac stage, high proximal well pressures cause compressive force on the proximal end of plug  10 . This force is transferred through proximal grips  14  to the well casing. Differential well pressures during the frac stage may reach 35,000 kPa to 100,000 kPa (5000 to 15,000 psi) or more. Proximal grips  14  transfer axial force on plug  10  to ridges  15  in the casing couplings during the frac stage to resist these forces, thus causing high compressive forces in grips  14 . Alternately, proximal grips  14  may transfer the forces to the casing directly through teeth or other features on grips  14 . Alternately, proximal casing grips  14  may be expanded and retracted by a rotating an inner threaded member or by a rotating an inner piston or by other means. Alternately, another means of anchoring the plug  10  against the casing may be employed. 
         [0084]    Axial port  7  preferably passes through proximal cam piston  77  offset from piston  77  centerline to transfer fluid to proximal cam cylinder cavity and sealing piston cylinder cavity  86 . Electrical and signal cables from Hall effect sensors, temperature sensors, pressure sensors, and other sensors in sensor cavity  16  and from other locations proximal to pistons  76  and  77  may pass through center conduit  70  which passes through both proximal pistons to the sensor electronics PC board. Both proximal cam piston  77  and sealing piston  76  seal on center conduit  70 . 
         [0085]    The distal and proximal cam cylinders  48  and  86  and distal and proximal cam pistons  45  and  77  are preferably fabricated from high tensile strength steel, titanium alloy, metal matrix composite, ceramic, or any other suitable material. They may be shot peened, nitride treated, heat treated, or otherwise processed to increase hardness and wear resistance. They may be plated or otherwise treated for corrosion resistance and wear resistance. 
         [0086]    Elastomeric seal  9  is expanded as shown in  FIG. 9  after plug  10  has reached its proper axial location for a frac stage. As shown in  FIG. 7  and  FIG. 8 , proximal cam piston  77  and sealing piston  76  share common cylinder cavity  86  and are activated sequentially to expand grips  14  and elastomeric seal  9 . Alternately, another design may be used (e.g, with separate cylinders for each piston). Pressure to operate seal piston  76  is supplied through port  7  as shown in  FIG. 8 , which passes through adjacent proximal cam piston  77 . The hydraulic pressure required for seal piston  76  to overcome return spring  78  preload force and initiate motion by compressing return spring  78  is preferably higher than the hydraulic pressure required for adjacent proximal cam piston  77  to reach its end of travel. Seal piston  76  urges the tapered proximal end of annular wedge  75  shown in  FIG. 9  to slide axially into the distal inner diameter of elastomeric seal  9 , thereby radially expanding seal  9  to form a pressure resistant seal against the well casing ID to prevent proximal pressure loss from the frac stage. Elastomeric seal  9  is preferably fabricated from a high temperature chemical resistant polymer or copolymer such as DuPont Viton, FKM flourocarbon, FPM, FFKM perflouroelastomer, flouropolymer, silicone, blends of these or other polymers, or any other suitable material. Alternately, an expanding sleeve (e.g., mechanically) may be used to increase the elastomeric seal ID. Alternately, a leadscrew or other mechanism may be used to slide one or more tapered elements to expand seal element  9 . Alternately, radially expanding overlapping or helical overlapping cam segments or helical cam segments may be used. Alternately, a non-elastomeric material may be used for seal  9 . Alternately, the seal may have another design. Alternately, another type of seal (preferably releasable or reusable) may be used. 
         [0087]    Protective rings  73  and  74  on either side of elastomeric seal  9  are slightly larger in diameter than the retracted outer diameter of seal  9  to protect seal  9  from abrasion or other damage as plug  10  is inserted or retracted from the well or moved along the wellbore. Protective rings  73  and  74  may additionally protect plug  10  as it passes burrs and other imperfections on the casing ID resulting from pyrotechnic perforations and from other causes. 
         [0088]    An accumulator may optionally be built into proximal piston  77  to cause elastomeric seal  9  to maintain constant force against the casing ID even though elastomeric seal  9  may experience viscoeleastic creep, or proximal three-way valve  128  may bleed down under pressure. Optionally, additional fluid may need to be pumped into seal piston cavity  86  to maintain sealing pressure during extended frac stages. 
         [0089]    Preferred casing grip  13  is shown in  FIG. 10 . Casing grip  13  may lock onto the well casing at any suitable location along the casing. Casing grip  13  design is preferred for use on both distal grips  13  and proximal grips  14  on plug  10 . Preferably, casing grip hinge bore  103  is located proximal to grip teeth  112  for both distal grips  13  and proximal grips  14  on plug  10 . The distal portion of casing grip  13  is displaced radially outward to grip the ID of the well casing. Casing grip teeth  112  are intended to secure casing grip  13  by impressing teeth  112  into the casing wall ID by radially outward forces acting on cam roller  47  by cam piston shallow ramp section  43 . Teeth  112  increase their well casing gripping force as frac pressures increase because the grip geometry causes grip teeth  112  to have the beneficial effect of transferring increasing force to the casing wall as proximal well pressure on plug  10  proximal end increases during the frac stage. Teeth  112  may be configured to have a cylindrical perimeter or a barrel-shaped perimeter in order to maximize grip contact area for variable well casing diameters. Alternately, another suitable tooth perimeter shape may be used. 
         [0090]    Casing grip  13  rotates on hinge pin  104  which preferably resides in hinge bore  103  with respect to plug  10  body. Casing grip  13  is preferably designed to transmit force to plug  10  body instead of requiring hinge bore  103  to bear all the proximal force resulting from the high frac pressure. Hinge bore  103  may be a slotted bore or an enlarged diameter bore with sufficient clearance to enable grip end surface  108  to transmit proximal force to plug  10  casing instead of requiring hinge bore  103  or its corresponding hinge pin to carry the full load. 
         [0091]      FIG. 11  shows an alternate embodiment of proximal casing grip  14 . Cylindrical surface  100  of grip  14  preferably bears upon the reduced inside diameter of flange  15  (see, e.g.,  FIG. 23 ) in a casing coupling. Conical surface  101  of grip  14  bears upon the proximal flange chamfer on casing coupling  2  flange  15 . 
         [0092]    Casing couplings  2  featuring integral flanges  15  as shown in  FIG. 23  are optionally inserted with the well casing string unless expandable flanges or flange segments are later inserted into the casing. Alternately, discrete flange segments may be placed between the ends of the casing joints using conventional couplings. Alternately, the well casing itself can be formed to have the flanges. 
         [0093]    Typical frac stages are spaced at 15 m (50 foot) intervals along the well. With an extension cylinder  32  stroke of 46 cm (18 inches), 33 cycles are needed to move repositionable plug  10  15 m (50 feet) proximally for each successive frac stage. Alternately, a different spacing interval may be used. Alternately, the spacing interval may vary between stages. Optionally, repositionable plug  10  may receive inductive signals or pressure signals or other signals transmitted from the wellhead or any other suitable location to command plug  10  to move a specified distance along the wellbore, perforate the well casing, move into position, and seal the well bore for the next frac stage. Optionally, plug  10  may compute the optimal frac stage spacing based on measured parameters and move the appropriate distance in accordance with these calculations, perforate the casing, move distally into position, lock onto the casing, and expand seal  9  in preparation for fracing that well stage. Optionally, plug  10  may transmit a signal through induction coupling to the well casing or other means such as by pressure wave generated by a pyrotechnic device to communicate its readiness for the next frac stage. 
         [0094]      FIG. 12  shows an enlarged view of the center section of repositionable plug  10  with the outer casing removed. Three-way valves  126  and  127  are mounted on distal valve body  20 . Distal valve body  20  transfers fluid through the coaxial tubes  29 , which pass through hydraulic reservoir  22 . Coaxial tubes  29  may be used instead of two separate tubes to minimize friction losses and leaks at reservoir piston  23 . Alternately, another tubing design may be used. Preferably hydraulic reservoir  22  capacity is equal to at least the sum of the piston displacement volumes to enable fully independent movement of all of the independent pistons on plug  10 . Pressure sensors are preferably placed on both high and low pressure ports on both proximal valve body  21  and distal valve body  20 . 
         [0095]    High flow rate three-way solenoid valves  126 ,  127 , and  128  are preferably used to obtain rapid depressurization of cylinders  34 ,  48 , and  86  for faster movement of plug  10  up the well. Hydraulic supply and return lines  121  and  122  direct hydraulic fluid to and from three-way valves  126  and  128  on proximal valve body  21  as shown in  FIG. 12 . Proximal valve body  21  is preferably bolted on to a proximal cylinder body. Proximal valve body  21  ( FIG. 13 ) preferably has a three-way solenoid valve  128  with pressure sensors. Hydraulic pressure is supplied by pump  19 , which also supplies distal valve body  20 . Flexible stainless steel tubing sections  134  and  135  are preferably placed on the hydraulic lines  121  and  122  to and from proximal valve body  21  to prevent the need to open the hydraulic system when plug shell  11  is opened for inspection and battery replacement. Alternately, another type of fluid connection may be used. 
         [0096]    Cable slot  131  provides a continuation of conduit  70  pathway from the proximal sensor cavity to the distal electronics board, enabling the cabling for temperature sensors, pressure sensors, Hall effect sensors, and other sensors to pass through the proximal pistons and cylinders from sensor cavity  16  to circuit boards  132  and  133 . Sensor PC board  132  and processor PC board  133  are preferably remote from or shielded from motor to minimize electrical interference and signal degradation. 
         [0097]    Downhole temperatures can reach 176 C (330 F) for onshore fraced wells and 204 C (400 F) for ultra deepwater wells. Therefore, batteries  17  are preferably lithium thionyl chloride batteries due to their high temperature capability and high energy capacity. Alternately, sodium sulfur, other lithium chemistries, or any other suitable type of battery may be used. Alternately, higher or lower temperatures may be reached. The battery cells are preferably stacked in series and parallel as needed to provide the necessary current and voltage for the electronics operation and for motor and valve operation. Cells may be matched in series or parallel arrangement to optimize power transfer and battery life. 
         [0098]    Batteries  17  may be isolated within pressure resisting bulkheads. Hermetically sealed electrical feedthroughs may optionally be used to prevent battery pressures or fluids from affecting other components of the system. The battery compartment may optionally filled with an inert gas or fluid and designed to protect against fire, explosion, or leakage of battery fluids and gasses and to dissipate heat. A vent port may optionally vent gasses above a certain pressure to prevent explosion if needed. 
         [0099]    Optionally, one or more capacitors may be placed in circuit with batteries  17  to supply high current pulses when needed. An ultra capacitor or a motor/generator-driven flywheel or a set of motor-driven counter-rotating flywheels may be optionally used to store and retrieve energy for power bursts, if desired. Alternately, instead of batteries, mechanical elements such as springs may be used for energy storage. Alternately, a compressed gas may be used for energy storage. Alternately, downhole mud motors may be used. Optionally, hydraulic lines pass through the battery cavity from pump  19  to proximal valve body  21  to direct hydraulic fluid to and from drive piston cylinder  243 , idler piston cylinder  244 , and accumulator  270  (see, e.g.,  FIG. 17 ). 
         [0100]      FIG. 14  shows a diagram of one embodiment of the hydraulic system for plug  10  described above. In  FIG. 14 , motor  18  drives pump  19  that draws hydraulic fluid from reservoir  22 . Optionally, an anti-leak back valve or check valve on pump  19  prevents fluid under pressure from flow back into pump  19 . Fluid is then directed through three-way valves  126 ,  127 , and  128  to extension cylinder  32 , distal cam cylinder (cavity)  48 , proximal cam cylinder  86 , and seal cylinder  86  (in shared cylinder embodiment). Maximum hydraulic pressure in the system is preferably below 21,000 kPa (3000 psi). Alternately, another pressure may be used. 
       Control System 
       [0101]      FIG. 21  shows the block diagram of one embodiment of plug  10  control system. In  FIG. 21 , microcontroller or digital signal processor  150  is preferably operable at high downhole temperatures of up to 176 C or 204 C or higher, such as the Texas Instruments TMS320 series, is used as the main controller. A high temperature chipset preferably capable of operating at high ambient temperatures to support the microcontroller is preferably collocated on a high temperature printed circuit board, signal conditioning circuit board  132 , and motor and valve control circuit boards. The high temperature printed circuit boards may be fabricated from polyetheretherketone (PEEK) composite, polyetherimide (PEI) composite, epoxy/glass fiber composite, or other suitable material. The high temperature printed circuit board preferably uses high temperature circuit components and high temperature solder. The high temperature circuit boards may optionally be immersed in flourocarbon fluid or other suitable thermally conductive substance to maximize heat dissipation. 
         [0102]    Microcontroller  156  preferably incorporates firmware or software to interpret the sensor signals and issue commands to hydraulic pump drive motor  19  and hydraulic solenoid valves  126 ,  127 , and  128  via pulse width modulated outputs. Pulse width modulated output signals from the microcontroller are preferably amplified through high temperature MOSFETs or by other amplification techniques well known to those skilled in the art. Output signals from sensors such as Hall effect sensors  158  to detect ridges  15  on the casing and Hall effect sensors  158  or other sensors to detect DR tool auger  151  axial distance are preferably electrically filtered and provided as inputs to the analog to digital converter on microcontroller  156 . Other sensors, such as hydraulic pressure sensors, downhole temperature sensors, motor temperature sensors, and electronics temperature sensors are preferably similarly conditioned and connected. 
         [0103]    One or more strain gages  157  to sense downhole pressure pulses as signals for the beginning or end of frac stages are preferably configured as Wheatstone bridges and connected as inputs to the analog to digital converter on microcontroller  156  after optional amplification. Hall effect sensors  158  or other sensors sense motor position and velocity information and are also preferably connected as high priority inputs to the analog to digital converter of microcontroller  156 . Additional sensors for motor current, valve current, and hydraulic pressures may be optionally used. The presence of an insertion or extraction tool may be detected with a with Hall effect sensor on repositionable plug tip  81 . 
         [0104]    An alternate embodiment of the plug  10  positioning system is shown in  FIG. 17 . This alternate design employs a tractor drive through drive wheels  241  instead of proximal and distal grips  14  and  13  and extension cylinder  32  as described above. The positioning system enables plug  10  to advance proximally along the well casing from the current frac stage to the adjacent proximal frac stage. Alternately, repositionable plug  10  can travel in the distal direction down the well casing. The drive system is designed to move plug  10  along the wellbore even when the wellbore is packed with proppant after the frac stage is completed. The alternate drive system may be incorporated on either the proximal or distal end of plug  10 . 
         [0105]    The drive system preferably has at least two drive wheels  241  and a single opposing idler wheel  242 , or alternately two idler wheels  242  and a single opposing drive wheel  241 . The combination of two wheels offset from the centerline on one side of plug  10  with a second opposing wheel centered on the opposite side of plug  10  creates a centralizing moment along the casing axis to keep the axis of the plug  10  centered on the axis of the well casing. Preferably, at least one drive wheel  241  is in contact with the well casing at all times while the drive system is active, even as drive wheel  241  passes over open frac ports  214  in the wall of casing segment  210 . 
         [0106]    Drive wheels  241  are preferably grooved for improved traction and have a semi-conical or tapered outer surface to fit the inside diameter of the well casing. Grooved drive wheels  241  preferably having semi-conical or semi-spherical outer surfaces are preferably fabricated from titanium alloy or other high strength steel alloy or metal matrix composite other material and coated or plated for corrosion resistance. O-rings are preferably placed in grooves on both sides of drive wheels  241  to prevent proppant and fluid intrusion into the gear cavity of drive piston  251  shown in  FIG. 18 . 
         [0107]    Torque produced by drive wheels  241  preferably produces sufficient axial force to overcome resistance to motion from residual proppant buildup proximal to the repositionable plug  10  as it moves proximally from frac stage to frac stage. Furthermore, enough torque is preferably generated by motor  233  through gearbox  239  to enable plug  10  to drive up and down chamfers and other features leading into and out of port slide  211  in  FIG. 19 . 
         [0108]    Drive cylinder  243  is configured to receive drive piston  251  shown in  FIG. 17 . Cylinder  271  holds pressure to create force to urge drive wheels  241  against the inside of the casing wall, thus enabling motion of plug  10 . Drive cylinder  271  preferably has an adjacent opposing idler piston cylinder  274  to maintain plug  10  centered longitudinally in the well casing. 
         [0109]    Accumulator  270  provides for approximately constant fluid pressure to maintain approximately constant radial force on drive wheels  241  and idler wheel  242  even as drive and idler wheels pass over imperfections in casing and variations in casing inside diameter. Accumulator  270  may use a piston opposed by one or more Belleville washers or other spring elements to provide force against piston inside accumulator  270 . Alternately, accumulator  270  may be charged with nitrogen or other gas. Accumulator  270  piston preferably has one or more o-rings or other sealing elements to seal against accumulator cylinder wall to maintain pressure in accumulator  270 . Hydraulic passages couple drive and idler cylinders to accumulator  270  and the input port. One or more bleed valves allow for bleeding air and gas out of the hydraulic system as needed. Preferably, coiled flexible hydraulic tube allows for disassembly of the unit for battery and component replacement without requiring the hydraulic system to be opened. 
         [0110]      FIG. 18  shows a perspective cross-sectional view of drive piston  251  with double U-joint  259 , which connects to gearbox  239 , and motor  233 . As shown in  FIGS. 17 and 18 , motor  233  transfers torque to drive wheels  241  through gearbox  239 , double U-joint  259 , and input shaft  258  to drive helical spur input gear  253 , which drives crossed helical spur gear  261  on countershaft  255 . Helical spur gear  261  is of the same handedness as input gear  253 . Helical spur input gear  261  preferably drives output helical spur gear  254  of opposite handedness as input helical gear  261 . Countershaft  255  provides additional mechanical offset of the input shaft from output shaft  257  to maximize the diameter of the drive wheels  241 . Preferably, sleeve bearings are used on the input shaft, countershaft, and output shaft. Preferably, a brazed or welded or otherwise bonded cover  259  on drive piston  251  keeps foreign material out of the internal gear cavity in drive piston  251 . Alternately, a worm gear or chain drive system or other means may be used to transfer power from the motor to the drive wheels. 
         [0111]    A compression spring (not shown) in cylinder cavity  243  returns piston  251  to its initial retracted position inside drive cylinder  271  when force exerted on the piston  251  by pressure in the cylinder  271  decreases below the return spring compression force (see,  FIGS. 17 and 18 ). Drive piston cylinder  271  and idler piston cylinder  274  are preferably fluidly connected to equalize pressure. Therefore, compression spring on idler piston  260  retracts idler piston  260  back into plug  10  after hydraulic pressure is reduced in idler piston cylinder to allow insertion and extraction of plug  10 . Stainless steel or other o-rings on cylinder heads  272  and  273  of plug  10  provide sealing against high well pressures at high ambient well temperatures. 
         [0112]    Driveshaft  258  prevents drive piston  251  from rotating, thus keeping drive wheels  241  aligned with the plug  10  axis. Similarly, a pin in a slot of idler piston  260  prevents idler piston  260  from rotating. Alternately, another means may be used to maintain alignment of the drive wheels  241  and idler wheel  242 . 
         [0113]    Double U-joint  259  is capable of maintaining continuous torque to the drive wheels  241  even as piston  251  moves up and down in drive cylinder  243  with variations in well casing inside diameter. Alternately chain drive or worm gear or magnetic drive or other means may be employed to drive the drive wheels  241 . Alternately, drive wheels  241  are not used and two or more moveable feet may be used to reposition the well plug  10 . 
         [0000]    Use with Casing Sleeves 
         [0114]      FIG. 19  shows a cross-sectional perspective view of a casing segment  210  with the port slide  211  in the closed position without repositionable plug  10  present. The casing segment is preferably in this closed configuration sealing the frac ports  214  when the casing string is inserted into the borehole. The casing segment as shown in  FIG. 19  has threads  212  sized to mate with the well casing. The well casing is not shown in  FIG. 19  or  FIG. 20 . A ridge  215  is preferably present on the inside diameter or other area of the port slide  211  which enables plug  10  to engage with the port slide  211  to open it. Once port slide  211  is opened, ridge  215  on port slide  211  provides structural support to hold plug  10  stationary under high pressure during the fracing process. Alternately, another type of interface feature such as one or more grooves or holes in port slide  211  may be used to secure plug  10  in port slide  211 . Alternately, ridge  215  may be placed elsewhere to support the plug. Alternately, ridge  215  in sleeve is not required if, e.g., plug  10  includes casing grips to grip the well casing ID. 
         [0115]    Preferably, one or more shear pins  218  lock port slide  211  to casing segment  210 . The shear pins are preferably sized to keep the hydrodynamic forces generated due to high fluid flow rate and high density of proppant slurry during distal fracs from inadvertently opening port slide  211 . Forces intentionally generated by wellhead pressure acting against the proximal surface of plug  10  act to slide port slide  211  open at the appropriate time during the well completion process. Proximal grips  14  are preferably used to capture the ridge  215  to open port slide  211  under the application of well pressure to open port slide  211  by sliding it distally. Proximal grips  14  are preferably moved into place prior to seal  9  deployment so that seal  9  can seal properly against port slide  211  inside diameter to accommodate variable port slide  211  inside diameters, out-of-round port slides  211  and slightly tapered port slides  211 . Alternately, well pressure or axial force generated by plug  10  extension cylinder  32  or tractor drive may act to slide port slide  211  open. Alternately, another means may act to slide port slide  211  open. Port slide  211  and the casing segment  210  are preferably corrosion resistant, having been plated with nickel or other corrosion resistant plating or coating after machining and/or honing. O-rings  219  provide for sealing against fluid or gas leakage. 
         [0116]    Referring to  FIG. 20 , the casing segment  210  is shown with port slide  211  in the open position without plug  10  present. During wellhead pressurization for fracing the current well stage, proximal grips  14  transfer force generated by pressure in the well acting against proximal end of plug  10  to ridge  215  of port slide  211  to keep plug  10  in place under the pressure of the frac, which may reach 100,000 kPa (15,000 psi) or higher. 
         [0117]    Ports  214  in the casing wall are preferably axially elongated as shown in  FIG. 19  and  FIG. 20  to provide sufficient proppant and fluid flow area while being narrow enough to enable plug  10  to have at least one drive wheel  241  in contact with the casing at all times even as drive wheel  241  passes over frac ports  214  with port slide  211  open. Alternately, ports  214  may be another shape. The distal end of port slide  211  may reside in a pocket in the casing segment  210  to prevent the motion of the port slide  211  from being impaired by cement intrusion after cementing operations. A linkage or sleeve may link two or more port slides  211  together in the casing string to enable them to open together as a set if desired. 
         [0118]    After the wellbore is drilled, the casing string is inserted into the wellbore with frac ports  214  on casing segments  210  sealed by port slide  211  in the closed position to prevent pressure loss from the well casing, enabling both cementing operations and later the fracing of distal stages of the well. If casing sleeves are employed, wireline tools may be used to check the wellbore to ensure that casing sleeves do not have excessive residual cement from cementing operations prior to fracing the well. Excessive residual cement may be removed prior to fracing with wireline tools if needed. 
         [0119]    During the fracing of the current frac stage, plug  10  is placed into position with sealing element  9  sealing against port slide  211 . Proximal grips  14  of plug  10  seat against ridge  215  of port slide  211 . Upstream well pressure is applied to plug  10  which transmits force through proximal grips  14  to ridge  215  of port slide  211  to slide port slide  211  distally to open frac ports  214 . The current stage is fraced, followed by a series of pressure pulses from the wellhead to signal to plug  10  to begin the sequence of actions needed to move plug  10  to the next proximally adjacent port slide  211 . Alternately, an electromagnetic induction signal may be transmitted down the casing or a magnetic or ultrasonic transmitting ball may be dropped down the well, or other means may be used to transmit a signal to plug  10  to extend drive wheels  241 , retract seal  9 , and reposition plug  10  to the adjacent proximal port slide  211  or another location in preparation for the next frac stage. 
       Deployment and Retrieval Tool 
       [0120]      FIG. 15  shows one embodiment of DR tool  150  used to insert plug  10  into the well and to position it at the proper axial location along the wellbore. This same DR tool  150  may additionally used to retrieve plug  10  from the well after the frac stages are completed.  FIG. 15  shows DR tool  150  threaded onto helix  80  on the proximal end of repositionable plug  10 . 
         [0121]    The proximal end of DR tool  150  is preferably attached to a wireline or slickline as shown in  FIG. 15 . Hereafter, “wireline” is used to refer to “wireline or slickline.” Wireline  159  provides precise insertion positioning of plug  10 , power for DR tool  150 , signal transmission to and from DR tool  150  and plug  10 , tethering, and a tensile element for retracting plug  10  from the well after the frac stages are completed. DR tool  150  axial position along the well is preferably controlled by wireline  159  cable length deployed down the well. Repositionable plug  10  may be retrieved after one or more frac stages and then replenished with new batteries, recharged, or replaced with another plug  10 . Alternately, it may be recharged downhole. Repositionable plug  10  preferably performs multiple frac stages in the well. An induction coil on DR tool  150  can transmit data through electromagnetic signals to a coil on plug  10  configured to receive the signals. 
         [0122]    Both DR tool  150  and plug  10  are preferably short enough in length to readily pass through a radiused section of casing in horizontal wells without becoming stuck in the casing or causing excessive friction while moving along the casing. DR tool  150  or plug  10  may optionally contain a movable joint along its length to allow it be flexible enough to pass through radii and doglegs along the wellbore. 
         [0123]    With slight wellhead pressure caused by pump flow, DR tool  150  is run down the well casing to just proximal to the known location of the repositionable plug. The deployed wireline cable length and slight wellhead pressure control the position of DR tool  150  and plug  10  during well insertion to cause DR tool and plug  10  to be inserted to the proper well location for the most distal frac stage. During insertion, seal  9  and grips  13  and  14  are preferably retracted. 
         [0124]    In addition to monitoring the location in the well casing through the length of wireline deployed, DR tool  150  preferably incorporates radially sensing Hall effect sensors or other sensors to detect ridges  15  in casing couplings or to detect the casing couplings itself as DR tool  150  travels along the well. Alternately, ultrasonic sensors, capacitance, or another means is used to sense ridges  15 . Alternately, gamma ray detection or another method may be used to determine the precise location to release repositionable plug  10 . 
         [0125]    Preferably, DR tool  150  contains circuitry and software to acquire, process, and transmit sensor information to the operator or wireline control system at the wellbore. Through this information, potentially more accurate information on the relative distance of DR tool  150  from plug  10  may be obtained. Electrical power to DR tool  150  is preferably provided through the wireline tether  159 . Alternately, batteries or other energy storage devices provide power. 
         [0126]    Wireline  159  may be carefully controlled to exactly position plug  10  in the proper location for the first frac stage. Alternately, DR tool  150  releases plug  10  just distal to the desired location and plug  10  positions itself in proper location relative to ridge  15 . 
         [0127]    Once plug  10  is in the correct location, DR tool  150  is remotely actuated through a wireline signal transmitted through coils in DR tool  150  or through the well casing or by another means such as ultrasonic signals or pressure pulses to plug  10  to extend grips  14 . Then after the appropriate time delay for grips  14  to extend, (and optionally some feedback from repositionable plug that it happened) DR tool distal head  151  rotates to release repositionable plug  10 . An optional magnet on DR tool  150  conveys information picked up by plug  10  tip hall sensor that DR tool  150  auger  151  has released plug  10 . After a suitable time delay for DR tool  150  to be moved distally, plug  10  moves into position adjacent to ridge  15 . 
         [0128]    If separate pyrotechnic perforation guns are deployed from the wellhead, these guns may optionally contain induction coils, pressure pulsing devices, or other means to transmit commands to plug  10  to pause its motion and seal against casing inside diameter temporarily while the pyrotechnic perforation charges are detonated. In this way, plug  10  may be protected against damage from resulting shock waves. 
         [0129]    Preferably, plug  10  incorporates a set of perforation guns. Alternately, after DR tool  150  is removed after insertion of plug  10 , separate perforating guns are sent down the wellbore to the proper location just proximal to plug  10  to create perforations in the casing. Optionally, the separate perforation guns are configured to send an electromagnetic signal or pressure signal or other signal to plug  10  that they are ready to perforate the casing. Optionally, the separate pyrotechnic perforating guns may receive a signal such as a pressure pulse, ultrasonic signal or other signal, from the repositionable plug to confirm that plug  10  is in position ready for perforation to take place. One or more pressure shock waves are likely to result from the pyrotechnic explosions creating the perforations. The seals on the repositionable plug are preferably designed to prevent fluid intrusion due to these shock waves. Alternately, other perforation techniques may be used. 
         [0130]    Repositionable plug  10  is preferably designed to operate even when the wellbore is packed with residual proppant such as Ottawa White sand or ceramic proppant or other proppant suspended by guar or other gel after a frac stage is completed. Such residual proppant buildup is commonly found after the frac stage is completed. Because residual proppant and gelling agent will typically remain in the wellbore after the frac stage is completed, DR tool  150  is preferably designed to move through the residual proppant pack when retracting plug  10 . To meet this need, one embodiment of DR tool  150  preferably features a rotating head on the distal end. DR tool  150  preferably contains a motor and gearbox or other means to drive the rotating auger  151  on DR tool  150  distal end. To ease motion through the residual proppant pack, DR tool  150  rotating auger  151  optionally has a helical strake  153  on the outer surface as shown in  FIG. 22  to assist in augering through the proppant to reach and connect with plug  10  to enable retrieval. An inner helix  154  on the inside diameter of auger  151  is designed to engage onto the tip helix  80  of plug  10 . Holes  155  in auger  151  allow proppant inside rotating auger  151  to be displaced outside of rotating tip. The pitch of helical strake  153  and the inside diameter helix  154  are preferably optimized based on the type of proppant, density, gelling agent, and other parameters. 
         [0131]    Axial rotation of auger  151  about DR tool  150  axis provides engagement or disengagement with tip helix  80  of plug  10 . Fins along sides of DR tool  150  body help prevent rotation of DR tool  150  due to torque reactions. Optional retractable guides or rollers on extendable members from DR tool  150  body may optionally press against the well casing ID to help center DR tool  150  and prevent rotation of DR tool  150  body and wireline  159  when torque is applied to rotate the end effector. Alternately, another design may be used. 
         [0132]    A locking feature such as a pawl or a plug which inserts into a mating feature on the helical tip  80  of plug  10  preferably locks plug  10  to DR tool  150  to prevent plug  10  from separating from DR tool  150  during insertion or operations up or down the well. 
         [0133]    Preferably, both DR tool  150  and plug  10  are equipped to sense the presence of each other. In one embodiment, one or more magnets or electromagnets is located in or near the rotating head of DR tool  150  to be sensed by Hall effect sensors in tip cavity  87  on plug  10  shown in  FIG. 8  to sense when plug  10  helical tip  80  is fully engaged with the extraction tool, in order that plug  10  may release grips  14  and/or  13  on well casing ID. Sensor signals for position and state feedback from DR tool  150  may be sent through modem or other means up the wireline tether  159  to an operator or control system at the wellhead. This same configuration of magnets and sensors may be used to signal to DR tool  150  that DR tool  150  has separated from plug  10  after insertion to proper depth in the well. 
         [0134]    The extraction tool may be the same tool as the insertion tool or it may be of a different design. Alternately, it may have some features that are only used for insertion and other features only used for extraction. Alternately, the insertion tool may simply consist of electromagnet using current sent down the wireline tether  159  to hold onto tip  80  of plug  10  during insertion. 
       Repositionable Plug Operation 
       [0135]    The operation of repositionable multi-state plug  10  during a well frac begins after the casing has been installed with optional casing segments including the port slides. The well is cemented if required, or swellable or other packers may be used to isolate frac stages along the wellbore. The casing sleeves may remain in the well for extended periods of time prior to well stimulation. Alternately, selected stages of the well may be stimulated initially and others stimulated at a later time. 
         [0136]    For onshore fracs, plug  10  is preferably used on set of at least two wells at a time in a “zipper frac” well stimulation operation. In the zipper frac, the casing of a first well is perforated for the impending frac stage while the stimulation of a frac stage of a second adjacent well on the same well pad takes place. In this way, the sequence of casing perforation and well fracing alternates between the two adjacent wells, optimizing equipment and crew utilization. Operation in this way is efficient because the typical duration of the fracing stimulation treatment is approximately one hour, which is approximately the time required for plug  10  to move to the new frac stage location in the adjacent zipper well, perforate the casing, move to its proper location for the frac, and expand seal  9  for the next frac stage. Optionally, the duration of the fracing treatment may vary by frac stage. Alternately, another time duration for plug movement may be used. Alternately, plug  10  may be used on a single well, or used for refracing previously fraced wells. Optionally, plug  10  is used in conjunction with coiled tubing to refrac existing wells. Alternately, plug  10  may be used in any other suitable way. 
         [0137]    The sequence of operations for a well frac using plug  10  is as follows: Plug  10  is inserted into the well through the wellhead preferably attached to the DR Tool. As the insertion tool and plug  10  are advanced along the well by the force of gravity and positive wellhead pressure, the wireline tether constrains velocity along the wellbore. As plug  10  advances down the wellbore, the wireline monitors the plug position along the well during the insertion process. Hall effect sensors or other sensors in DR tool  150  monitor the location of the casing flanges or casing joints. Plug  10  is decelerated and distal motion of plug  10  is halted as the proximal grips  14  arrive at a position immediately proximal to the coupling flange  15  on the distal end of the most distal well stage to be fraced. Alternately, plug  10  may be positioned at any other suitable location. Distal grips  13  are extended and grip the well casing inside diameter. DR tool  150  releases plug  10  by rotation of auger  151 . DR tool  150  is then withdrawn from the well. 
         [0138]    Plug  10  then senses the casing flange  15  location or casing coupling locations through its Hall effect sensors. Alternately, plug  10  may monitor its position by tracking cylinder  32  extension cycles or by another suitable method. Plug  10  repositions itself to perforate the well casing with onboard perforation guns. After perforating the casing, plug  10  moves distally to deploy proximal grips  14  to rest on the proximal flange surface of ridge  15  (if present) to resist the frac pressure. Plug  10  then forces elastomeric seal  9  against the casing wall. Grips  14  are preferably extended into place prior to seal  9  deployment so that seal  9  can provide proper pressure to accommodate variable well casing ID variation, out of round casings, and tapered casings. 
         [0139]    In this manner, plug  10  moves proximally along well bore from frac stage to frac stage, preferably stopping with proximal casing grips  14  just proximal to flange  15  on the casing coupling. Alternately, plug  10  stops just proximal to the coupling between casing joints. Alternately, plug  10  may stop at any other suitable location. 
         [0140]    The most distal stage of first well  1  is then fraced by pumping proppant and water and gelling agent and other chemicals down the well at the appropriate fracing pressure(s) for the desired amount of time. Alternately, waterless fracing or another fracing technique may be used. One or more pressure signals are then sent down the well and received by the pressure sensor (strain gage) in proximal portion of plug  10  to signal to plug  10  to advance to the next frac stage. 
         [0141]    Preferably, plug  10  is pre-programmed prior to insertion in the well with pressure vs. time profiles for frac stages and axial lengths of each frac stage. Alternately, plug  10  may respond to commands from wellhead pressure pulses or to electromagnetic signals sent down the well casing or to signals sent from a wireline tool to move the proper distance for the next frac stage. Alternately, frac stage lengths may be determined on the fly by plug  10  according to pre-programmed algorithms to analyze sensor data. Statistical methods or the assignment of sensitivity factors may be used to weight sensor readings to optimize frac stage spacing based on prior data sets. Alternately, sensor data may be transmitted from plug  10  to the wellhead for processing. 
         [0142]    For varying frac stage lengths, plug  10  traversal distance may be controlled from the wellhead by sending a series of induction signals transmitted down the well casing or pressure pulses corresponding to a string of 1&#39;s and 0&#39;s with optional checksum for accuracy, which are sensed by coils or pressure sensors such as strain gages on the proximal portion of the plug  10 . This series of pulses may be translated by the controller into a distance for plug  10  to move. Optionally, plug  10  may be sent pressure pulses from the wellbore or from optional independent perforating guns or from a wireline tool to command plug  10  to move a sufficient distance to skip a frac stage if needed. 
         [0143]    Pressure pulses or induction signals may be used to signal the start and end of a frac stage. Pressure pulse duration and amplitude may be monitored by plug  10  and compared to preset values using an pre-programmed algorithm. Alternately, communication to and from plug  10  may be accomplished by using electromagnetic pulses induced in the casing at or near the wellhead and conducted down the casing and picked up by coils or other sensors in plug  10 . 
         [0144]    Repositionable plug  10  then begins moving to the next most proximal frac stage by extending distal grips  13  to grip the well casing inside diameter, then retracting elastomeric seal  9 , and partially retracting proximal grips  14 . Extension cylinder  32  then extends to its full stroke, moving the body of plug  10  proximally along the wellbore. Proximal grips  14  are then extended and exert force to grip the well tool. Distal grips  13  are then partially retracted, the extension cylinder  32  is retracted, and distal grips  13  are extended to grip the well casing ID. Proximal grips  14  are then partially retracted, then extension cylinder  32  is extended again, and the process is repeated as plug  10  moves to the next proximal frac stage. Repositionable plug  10  moves into position for the frac stage by deploying proximal grips  14  to bear against the casing to lock it in place for the frac stage, and then extends elastomeric seal  9  against the well casing ID. 
         [0145]    Traversing the 15 m (50 foot) typical spacing between frac stages requires plug  10  to repeat the above sequence 33 times, assuming an extension cylinder  32  stroke of 46 cm (18 inches). Approximately 56 minutes is required to move plug  10  between frac stage locations, assuming 15 m (50 foot) intervals and a 46 cm (18 inch) extension cylinder stroke and 5.5 inch OD 20 lb/ft casing with 20/40 mesh Ottawa white sand used as proppant. Alternately, more or less time is required. Repositionable plug  10  can move proximally or distally along wellbore by reversing the sequence of proximal and distal grip deployments in coordination with extension cylinder movements. Once a distal stage is completed, the pressure produced by the reservoir or formation stimulated by that distal stage will help push the repositionable plug proximally to the next frac stage. 
         [0146]    It may be desired to partially retract proximal grips  14  and distal grips  13  as plug  10  moves between frac stage in order to keep plug  10  centered on the well casing ID during motion to protect elastomeric seal  9  from casing abrasion and tearing or other damage from pyrotechnic perforation generated burrs on the casing inside diameter. Typical burrs intrude 1 mm (0.040 in) to 2 mm (0.080 in) radially into the well casing. 
         [0147]    While repositioning plug  10 , hydraulic pressure in extension cylinder  32  is preferably monitored to prevent plug  10  from becoming stuck on a casing perforation burr. If plug  10  becomes stuck, an internal algorithm can move plug  10  distally by reversing the sequence to move it proximally, followed by additional attempts to move plug  10  proximally. Alternately, as plug  10  is moving between stages, independent perforating guns are sent down the wellbore from the wellhead to the proper location proximal to the final position of plug  10  to perforate the casing by using pyrotechnic charges. 
         [0148]    As plug  10  is moving and pyrotechnic perforations are being created for the next stage of well  1 , the repositionable plug in well  2  is sealing the wellbore while the frac stage is being fraced. Once that frac stage is completed, the frac pressure is relieved at the wellhead of well  2  and applied to the wellhead of well  1  to frac its current stage while the repositionable plug in well  2  moves to the next most proximal stage in same manner as described above. The two repositionable plugs thus alternate motion in the wells, as the wells are alternately fraced in a “zipper frac” operation. Plug  10  is capable of performing as many stages per well as needed with any stage length required. Alternately, the wells may be fraced using another suitable sequence. 
         [0149]    In addition to being useful for the fracing of new wells, the current invention simplifies the refracing of existing wells. In one embodiment of this technique, plug  10  follows the coiled tubing up the well, as successive stages are fraced to maintain frac zone isolation. The coiled tubing can send commands to plug  10  by pressure pulses, electromagnetic signals, or other means. Alternately, the present invention can also be used with sliding sleeves in the casing instead of casing perforations for both fracing and refracing operations. Alternately, the present invention can be used for stimulation of conventional reservoirs. Alternately, the present invention can be used for gravel packing of wells. 
         [0150]    DR tool  150  preferably decelerates and moves slowly as it approaches plug  10 . A bumper may be present on the distal end of the extraction tool to prevent DR tool from impacting plug  10  during downhole approaches. 
         [0151]    Once DR Tool  150  is in proximity to plug  10 , repositionable plug  10  senses electromagnetic signals or pressure pulse signals or other signals from DR tool  150 . DR Tool  150  locks onto plug  10  and grips  13  and  14  are retracted in preparation for extraction from the well. With DR tool auger  151  locked to plug  10 , DR tool  150  retracts plug  10  up to the wellhead. 
         [0152]    A number of methods and compositions are discussed in the Summary of the invention and further details are provided herein and in the Examples section. As would be readily appreciated by the skilled person, the disclosures can be read in combination. 
         [0153]    While the foregoing invention has been described in some detail for purposes of clarity and understanding, it will be clear to one skilled in the art from a reading of this disclosure that various changes in form and detail can be made without departing from the true scope of the invention. For example, all the techniques and apparatus described above can be used in various combinations. All publications, patents, patent applications, and/or other documents cited in this application are incorporated by reference in their entirety for all purposes to the same extent as if each individual publication, patent, patent application, and/or other document were individually indicated to be incorporated by reference for all purposes.

Summary:
Systems and methods are provided for moving a well casing plug to desired locations in a well. The well plug system can be located at a desired position, generate a reversible seal at the location, remove the seal, and relocate. Features of the plug system, such as translocating devices, actuating devices, sensors, and casing penetration tools can allow work to be done at various well hole locations, e.g., without requiring continuous physical connections or communications with the surface. The methods include sealing the well casing plug in a casing, opening ports through the casing, facilitating passage of fluids at hydraulic fracturing pressures to formations outside the casing, reversing the seal, and translocation of the plug system to a new location.