Patent Publication Number: US-11396793-B2

Title: Systems and methods for multi-stage well stimulation

Description:
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     BACKGROUND 
     Field of the Disclosure 
     The present disclosure presents a system and methods for stimulating a formation in multiple stages while providing an operator with flexibility in the stages that are to be stimulated or isolated from stimulation. 
     Background of the Disclosure 
     An oil or gas well includes a wellbore extending into a subterranean formation at some depth below a surface (e.g., Earth&#39;s surface), and is usually lined with a tubular, such as casing, to add strength to the well. 
     Downhole oil and gas production operations, and particularly those in multi-stage wells, require the stimulation and production of one or more zones of a hydrocarbon bearing formation. In many cases this is done by running a liner or casing string downhole, in which the liner or casing string comprises one or more downhole frac valves, including but not limited to ported sleeves or collars, at spaced intervals along the wellbore. 
     The location of the frac valves is commonly set to align with the formation zones to be stimulated or produced. The valves must be manipulated in order to be opened or closed as required. In the case of multistage fracking, multiple frac valves are used in a sequential order to frac sections of the formation, typically starting at a toe end of the wellbore and moving progressively towards a heel end of the wellbore. It is crucial that the frac valves be triggered to open in the desired order and that they do not open earlier than desired. 
     In some instances, the liner is arranged with valves having seats of increasing inside diameter progressing from toe to heel. The valves are manipulated by pumping balls, plugs or darts having sequentially increasing outside diameters down the liner. The first ball, having the smallest outside diameter passes through all frac valves until it seats on the first valve seat, having the smallest inside diameter. 
     When a ball lands on the seat, fluid pressure uphole of the ball forces the ball downhole and causes it to mechanically move a sleeve of the valve downhole to expose the ports of the frac valve. In this arrangement, each valve must be uniquely built with a specific seat size and must be arranged on the liner in a specific order. Additionally, a stock of balls of all sizes of diameter must always be maintained to be able to manipulate all of the unique valve seats. 
     In other cases, opening of the frac valve achieved by running a bottom hole assembly, also known as an intervention tool, down on a tubing string through the liner or casing string, locating in the frac valves to be manipulated and manipulating the valve by any number of means including use of mechanical force on the intervention tool, or by hydraulic pressure. However, the use of an intervention tool is not always desirable; the tubing on which the intervention tool is run presents a flow restriction within the liner and prevents the full bore fluid flow required within the liner to achieve the needed stimulation pressure. 
     US 2017/0175488 teaches an indexing mechanism on a dart for opening one or more valves in a liner. The indexing mechanism takes the form of a reciprocating sleeve formed on the dart. The reciprocating sleeve that moves with contact of every valve and the dart is then guided through a j-type slot until the indexing sleeve is in a position that it will engage and open a selected valve. 
     U.S. Pat. No. 9,683,419 teaches an electrical control module with sensors within the dart, the sensors detecting one or more contact points on the valve/sleeve to be opened. 
     US patent application 2015/0060076 teaches a ported tool  100  having a profile receiver set to match a profile receiver on a selective tool actuator having a matching profile key. Each ported tool has a profile receiver that is set to specific orientation that is different from all others, before being run downhole. The ported tools are in this sense in different configurations when run downhole. 
     CA 2,842,568 teaches that a sleeve of each frac valve in a liner system is provided with a groove of distinctive width to receive an outwardly biased member also with a distinctive width on a dart. The frac valves are arranged downhole so that sleeve grooves increase in width from heel to toe and darts with matching width biased members are deployed to actuate the desired sleeve. The patent also teaches an embodiment in which a dart can be disengaged from the designated sleeve and travel further downhole to actuate downhole sleeves. 
     However, a need still exists for simple but robust system in which identical frac valves can be run downhole and can be opened in any sequence by one or more darts. 
     There is therefore still a need for frac valve systems which does not necessarily require the use of an intervention tool or of unique frac valves and dedicated balls or plugs, but that can open one or more frac valves in any order desired, and also for systems that allow for repeatedly opening and closing one or more frac valves within the liner for varying purposes. 
     SUMMARY 
     Embodiments of the disclosure pertain to a downhole system for stimulating one or more stages of a downhole wellbore. The system may include one or more frac valves arranged on tubular; any of such frac valves presenting an identical inside profile to another, and any of which may be openable for providing fluid communication between internal and external of the tubular. There may be an at least one dart deployable into the tubular, and being adjustable to pass through one or more frac valves without opening one or more frac valves, and yet may be able to engage and open one or more other frac valves. 
     Other embodiments of the disclosure pertain to a system for stimulating a subterranean formation that may include a wellbore formed within the subterranean formation; and a tubular disposed within the wellbore. 
     There may be a first frac valve disposed within the tubular, the first frac valve having a first sleeve in a closed position, and further configured to move to an open position. There may be other valves, such as a second frac valve disposed within the tubular (which may be downhole from the first frac valve), the second frac valve having a respective (or second) sleeve in a respective closed position, and further configured to move to a respective open position. 
     The system may include a dart deployable into the tubular. The dart may be configured to pass through the first frac valve without moving the first sleeve to the open position. The dart may be configured to subsequently engage the second frac valve, and to move the respective sleeve to the respective open position. 
     The dart may include an adjustment mechanism. The mechanism may be adjustable or movable from a first position that allows the dart to pass through the first frac valve, to a second position that facilitates engagement of the dart with the second frac valve. The adjustment mechanism may include one or more of: a mandrel comprising an outer surface; an indexing sleeve moveably disposed on the outer surface, the indexing sleeve configured to control movement of the adjustment mechanism from the first position to the second position; an upper collet and a lower collet formed on the indexing sleeve; and a series of grooves formed on the outer surface, such that either of the upper and lower collet may be engageable by respective grooves as the indexing sleeve increments axially relative the mandrel. 
     The dart may include a restraint surface formed at an uphole end of the mandrel. The dart may include a mandrel shoulder formed at the uphole end of the mandrel 
     There may be a plurality of additional frac valves within the system. The total number of valves the dart passes through without opening any of may correspond to a total number of grooves of the series of grooves that are not covered by the indexing sleeve when the indexing sleeve is in the first position. 
     In aspects, any frac valve the dart passes through may increment the indexing sleeve axially along one groove of the series of grooves. 
     The at least one dart may have an uphole portion of the mandrel that is radially expandable to contact an inside diameter or surface of the second frac valve and form a seal. In aspects, the radially expandable uphole portion of the mandrel may have a tapered inside diameter. 
     The mandrel may have one or more ridges configured to form a seal when the dart is sealable against an inside surface of the second frac valve. 
     The mandrel may include a packing element disposed therearound, the packing element being radially expandable to form a seal between the dart and an inside surface of the second frac valve. 
     In aspects, the dart may be configured to open a respective sleeve of an additional frac valve. 
     The dart may have a cap on (e.g., a downhole end of) the mandrel to limit downhole movement of the indexing sleeve. The dart may include a bore through the mandrel to provide passage of production fluid. 
     The dart may include ball seatable on an uphole end of the dart to block a bore through the mandrel. 
     The system may include a second dart configured to move the first sleeve from the closed position to the open position. Any dart of the system may be flowable back upstream by movement of the indexing sleeve along the mandrel to allow the dart to pass upstream through any frac valve. 
     The second frac valve may include a temporary no-go shoulder formed on the respective sleeve, and a groove for receiving the temporary no-go shoulder when the respective sleeve is moved to the open position, thus allowing passage of the at least one dart through the second frac valve after the respective sleeve of the second frac valve has been opened. 
     The mandrel may be movable relative to the indexing sleeve to shift at least one of the upper collet and lower collet from a collet engaged position to a collet unengaged position. 
     These and other embodiments, features and advantages will be apparent in the following detailed description and drawings. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more detailed description of the present disclosure, reference will now be made to the accompanying drawings, wherein: 
         FIG. 1  shows a cross-sectional elevation view of a tubestring configured with an example of a system described herein according to embodiments of the disclosure; 
         FIG. 2  shows a cross-sectional elevation view of a tubestring configured a further example of a system according to embodiments of the disclosure; 
         FIG. 3  shows a cross-sectional elevation view of one example of a frac valve according to embodiments of the disclosure; 
         FIG. 4  shows a cross-sectional elevation view of one example of a dart with a corresponding ball according to embodiments of the disclosure; 
         FIG. 5  shows a cross-sectional elevation view of the frac valve of  FIG. 3  with the dart of  FIG. 4  and a ball engaged there within, in a frac valve open position according to embodiments of the disclosure; 
         FIG. 6  shows a cross-sectional elevation view of the frac valve of  FIG. 3  with the dart of  FIG. 4  and a ball engaged there within, showing an upper collet of the dart in an extended position to engage a shoulder of the frac valve according to embodiments of the disclosure; 
         FIG. 7  shows a cross-sectional elevation view of the frac valve of  FIG. 3  with the dart of  FIG. 4  and a ball engaged there within, showing the lower collet in an extended position and the upper collet of the dart in a retracted position such that the dart can travel through the frac valve and downstream according to embodiments of the disclosure; 
         FIG. 8  shows a cross-sectional elevation view of a subsequent frac valve downstream to the frac valve of  FIG. 7  with the dart of  FIG. 4  and a ball engaged there within, showing the lower collet in an extended position engaged with a shoulder of the subsequent frac valve, and the upper collet of the dart in a retracted position according to embodiments of the disclosure; 
         FIG. 9  shows a cross-sectional elevation view of the frac valve of  FIG. 8  with the dart of  FIG. 4  and a ball engaged there within, showing the lower collet now in a retracted position and now travelled downwardly past the shoulder, and the upper collet of the dart in an extended position now engaging the shoulder according to embodiments of the disclosure; 
         FIG. 10 a    shows a cross-sectional elevation view of a dart configured with a tapered inside diameter of a dart mandrel according to embodiments of the disclosure; 
         FIG. 10 b    shows a cross-sectional elevation view of a dart configured with a series of ridges on an outer surface of a dart mandrel according to embodiments of the disclosure; 
         FIG. 11  shows a cross-sectional elevational view of a dart configured with an elastomeric ring according to embodiments of the disclosure; 
         FIG. 12  shows a cross-sectional elevational view of a further embodiment of the dart, showing a flow back feature according to embodiments of the disclosure; 
         FIG. 13  shows a partial cross section view of a dart engaged in a frac valve according to embodiments of the disclosure; and 
         FIG. 14  shows a partial cross section view of a frac valve engaged with a dart according to embodiments of the disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     Herein disclosed are novel apparatuses, systems, and methods that pertain to downhole tools usable for wellbore operations, and aspects (including components) related thereto, the details of which are described herein. 
     Embodiments of the present disclosure are described in detail with reference to the accompanying Figures. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, such as to mean, for example, “including, but not limited to . . . ”. While the disclosure may be described with reference to relevant apparatuses, systems, and methods, it should be understood that the disclosure is not limited to the specific embodiments shown or described. Rather, one skilled in the art will appreciate that a variety of configurations may be implemented in accordance with embodiments herein. 
     Although not necessary, like elements in the various figures may be denoted by like reference numerals for consistency and ease of understanding. Numerous specific details are set forth in order to provide a more thorough understanding of the disclosure; however, it will be apparent to one of ordinary skill in the art that the embodiments disclosed herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Directional terms, such as “above,” “below,” “upper,” “lower,” “front,” “back,” “right”, “left”, “down”, etc., may be used for convenience and to refer to general direction and/or orientation, and are only intended for illustrative purposes only, and not to limit the disclosure. 
     Connection(s), couplings, or other forms of contact between parts, components, and so forth may include conventional items, such as lubricant, additional sealing materials, such as a gasket between flanges, PTFE between threads, and the like. The make and manufacture of any particular component, subcomponent, etc., may be as would be apparent to one of skill in the art, such as molding, forming, press extrusion, machining, or additive manufacturing. Embodiments of the disclosure provide for one or more components to be new, used, and/or retrofitted. 
     Numerical ranges in this disclosure may be approximate, and thus may include values outside of the range unless otherwise indicated. Numerical ranges include all values from and including the expressed lower and the upper values, in increments of smaller units. As an example, if a compositional, physical or other property, such as, for example, molecular weight, viscosity, melt index, etc., is from 100 to 1,000, it is intended that all individual values, such as 100, 101, 102, etc., and sub ranges, such as 100 to 144, 155 to 170, 197 to 200, etc., are expressly enumerated. It is intended that decimals or fractions thereof be included. For ranges containing values which are less than one or containing fractional numbers greater than one (e.g., 1.1, 1.5, etc.), smaller units may be considered to be 0.0001, 0.001, 0.01, 0.1, etc. as appropriate. These are only examples of what is specifically intended, and all possible combinations of numerical values between the lowest value and the highest value enumerated, are to be considered to be expressly stated in this disclosure. 
     Embodiments herein may be described at the macro level, especially from an ornamental or visual appearance. Thus, a dimension, such as length, may be described as having a certain numerical unit, albeit with or without attribution of a particular significant figure. One of skill in the art would appreciate that the dimension of “2 centimeters” may not be exactly 2 centimeters, and that at the micro-level may deviate. Similarly, reference to a “uniform” dimension, such as thickness, need not refer to completely, exactly uniform. Thus, a uniform or equal thickness of “1 millimeter” may have discernable variation at the micro-level within a certain tolerance (e.g., 0.001 millimeter) related to imprecision in measuring and fabrication. 
     Referring now to  FIGS. 1 and 2  together, the devices and systems described herein provide communication between an inside of a cased or lined wellbore and the surrounding rock formation. The casing or liner  2  may be cemented into the wellbore or packers  5  may be used to isolate sections of the casing or liner  2 . It may also be possible that the wellbore is both cemented and having packers  5 . The wellbore may be an open hole or a cased hole, or a hybrid thereof, with a portion cased and a portion open. The wellbore may be vertical, horizontal, deviated or of any orientation. 
     Multiple frac valves  6  can be installed along the length of the casing or liner string  2 . While the term liner is used throughout the present description, it will be understood that both casing string and liner string are to be inferred. 
     Frac valves  6  are installed onto the liner  2  and strategically spaced along its length. The order in which the frac valves are installed does not matter as the frac valves are all identical and have identical bores. 
     A toe valve  8  is placed near the lower, or toe end  10  of the liner  2 . The liner is run into the well. Whenever the liner  2  has reached the bottom of the well it may be cemented into the formation using known cementing methods, as shown in  FIG. 1 . Alternatively it may be left in the borehole without cement. As seen in  FIG. 2 , open hole packers  5  installed on the liner  2  may be used to provide isolation along the length of the liner  2 . 
     With reference to  FIGS. 3 to 13 , the present system is comprised of two main components; the frac valve  6  and a dart  14 . The frac valve  6  is installed on the casing or liner  2 , as mentioned before multiple frac valves can be spaced along the liner  2 . The dart  14  is pumped down the inside diameter of the casing or liner  2 . One or more darts  14  may be pumped down, depending on the number of stages of the formation to be stimulated. 
     With reference now to  FIG. 3 , the frac valves  6  installed on the liner  2  are all identical. There is no need for differing valves with differing seat sizes. The frac valves  6  do not need to be installed in any particular order. They all have similar end connections and the outside diameter (O.D.) and inside profiles are all also the same. The valve seats  16  of each frac valve  6  all hold the same profiles. These seats  16  act as a shiftable sleeve to expose port  18  to allow for fluid communication between an inside of the liner  2  and formation surrounding it. 
     For this reason, in some cases the valve seats  16  are also referred to as valve sleeves  16 , but it is to be understood that these two terms encompass the same element. The opening pressure required to shift the seat  16  is adjustable by adjustment of shear screws  20  that hold the seat  16  to the frac valve  6  body. Commonly all frac valves  6  on a liner  2  can be installed with the same opening pressure or shear value. 
     With reference to  FIG. 4 , in one embodiment, the present dart  14  comprises an adjustment mechanism in the form of an indexing sleeve  22 , a mandrel  24 , and a cap  36 . The indexing sleeve  22  defines an upper collet  28  and a lower collet  30 . The cap  36  prevents the indexing sleeve  22  from unintentional shifting. Grooves  32  located circumferentially around the outside diameter of the mandrel  24  control the location of the indexing sleeve  22 , as well as the position of the upper collet  28  and lower collet  30 . 
     A bevel  42  on the upper edge of the mandrel  24  serves as an initial ball seat. A seal  38  on the upper outside diameter of the mandrel  24  acts as secondary sealing device while fracing is in process. The dart  14  is provided with a bore  40  through the center of the mandrel  24  that provides passage for production fluid, the bore  40  large enough to present very little restriction to flow from the formation. 
     Both upper and lower collets  28 ,  32  are naturally biased radially inwardly. This bias helps to hold the indexing sleeve  22  in place on the mandrel  24 . A ball  200  is used to pump the dart  14  into the well and act as a pressure barrier during fracing procedures. 
     With reference to  FIGS. 6 to 9 , the passing of the present dart  14  through one or more present frac valves  6  is now described. A dart  14 , with a ball  200  resting on an uphole end of the mandrel  24  is pumped down into the liner  2 . It would be well understood that while a ball  200  is shown in the figures, a plug or any other means of blocking flow through the bore of the dart  14  can be provided without departing from the scope of the present disclosure. For example, the uphole or downhole ends of the mandrel  24  can be closed by a permanent or detachable cover. By way of further example, the mandrel cap  36  can optionally take the form of a solid cap, rather than a ring, to block flow through the mandrel at the downhole end of the dart  14 . 
     Although all of the frac valves  6  and darts  14  are identical, the distance between the indexing sleeve  22  and cap  36  on each dart varies. If the indexing sleeve  22  of a dart  14  is set to contact the cap  36 , such a dart is set to travel past all other frac valves and land on and engage a frac valve  6  closest to the toe end  10  of the liner  2 . As the indexing sleeve  22  location is set at incremental distances away from the cap  36 , the particular dart  14  is set to land on and engage a subsequent frac valves after the frac valve closest to the toe end  10 . 
     For example, and for illustrative purposes only, if the spacing between the indexing sleeve  22  and the cap  36  were to equal ¼″, then such a dart  14  is set to pass all other frac valves and land on and engage the second frac valve from the toe  10 . The length thus of the grooved  32  portion of the mandrel  24  of a dart is therefore set based on the number of frac valves  6  in a given liner. For example, the dart  14  illustrated in  FIG. 4  can be used when there are eleven frac valves  6  in the liner  2 . The length of the mandrel  24  and number of circumferential grooves  32  can be manufactured to suit the desired number of frac valves  6 . 
     Furthermore, the spacing between the grooves is not limited to ¼″; this distance is provided for illustrative purposes only. A spacer sleeve (not shown) can optionally also be used between the cap  36  and indexing sleeve  22  to ensure correct location of the indexing sleeve relative to the mandrel. 
     A dart  14  and ball  200  are deployed into the well and are pumped downhole until they contact a frac valve  6  closest to the heel  12  of the well. As seen in  FIG. 6 , the upper collet  28  on the indexing sleeve  22  lands on the shoulder  50  formed on the sliding sleeve  16  of the frac valve  6 . In another option, the lower collet  30  can be in a position to land on the shoulder  50  formed on the sliding sleeve  16 . In this sense, it would be well understood by a person of skill in the art that although the below description refers to an initial position in which the upper collet lands on shoulder  50 , the initial position of the dart  14  in the frac valve  6  can vary. 
     Pressure acting on the ball  200  generates a force on the mandrel  24  of the dart  14 . When this force exceeds the force required to overcome the bias and express the lower collet  30  radially outwardly between two grooves  32 , the upper collet  28  is radially retracted into an uphole subsequent circumferential groove  32  on the mandrel  24  and the mandrel is allowed to shift downhole relative to the indexing sleeve  22 , as seen in  FIG. 7 . 
     With the upper collet  28  now radially retracted, the dart  14  is now free to travel downhole through the bore of the frac valve  6 . The indexing sleeve  22  and mandrel  24  remain in this relative position until they reach the next frac valve  6  downhole in the liner  2 . At this point, as illustrated in  FIG. 8 , the lower collet  30  is expressed radially outwardly and contacts the shoulder  50  of the sliding sleeve  16  within the frac valve  6 . 
     Again, pressure acting on the ball  200  generates a force on the mandrel  24  of the dart  14  and when this force exceeds the force required to overcome the bias and express the upper collet  28  radially outwardly, the mandrel  24  shifts dowhnhole relative to the indexing sleeve  22  and the lower collet  30  snaps into an uphole subsequent circumferential groove  32  on the mandrel  24 . The dart  14  thus advances into the bore of the sliding sleeve  16  until the upper collet  28 , which is now expressed radially outwardly, lands on the shoulder  50  of the sliding sleeve, as seen in  FIG. 9 . 
     This process repeats itself at each frac valve  6  along the liner  2  until the upper collet  28  of the indexing sleeve  22  lands on a restraint surface  52  on the mandrel  24  that expresses the upper collet  28  radially outwardly. 
     The mandrel  24  with the restraint surface  52  supporting the upper collet  28  are unable to move further downhole relative the upper collet  28  due to a mandrel shoulder  54  formed on the mandrel  24 . At this point the upper collet  28 , transfers a compressive force into the sleeve  16  of the frac valve  6  via shoulder  50 . When the applied load exceeds the shear valve of the screws  20  holding the sleeve  16  to the frac valve  6 , the screws shear permitting the ball  200 , dart  14  and sleeve  16  to shift. This action exposes the frac ports  18 . The frac sleeve  6  is now open and stimulation fluid can be pumped through the ports  18  and into the formation, as seen in  FIG. 5 . As also seen in  FIG. 5 , the ball  200  has also be forced into an expandable uphole portion  24   a  of the mandrel  24  and seats on ball seat  42 . 
     When the sliding sleeve is being opened and during the frac, the expandable uphole portion  24   a  of the mandrel  24  is radially expanded and contacts an inside bore of the sliding sleeve  16 . this action forms a seal between the dart  14  and the sliding sleeve  16 ; it also transfers compressive load into the sliding sleeve  16 , augmenting the contact load between the upper collect 28 and the sliding sleeve shoulder  50 . A no-go shoulder formed on an inside surface of the frac valve outer body  44  limits the travel of the sliding sleeve  16  and transfers the force generated during the frac into the outer body  44  of the frac valve  6 . the frac valve  6  in turn transfers the load into the liner  2 . 
     In operation of the present system, in a first step, once the liner  2  is run down the wellbore, the frac valves  6  are isolated by either cementing or by activation of packers  5  or any other means. Applied fluid pressure down the liner causes the toe valve  8  to shift open, exposing ports in the toe valve  8  through which fluids can be pumped into the formation. This allows for fluid flow through the liner  2  and one or more ball  200  and dart  14  pairs can then pumped down the inside of liner  2 , since any displaced fluid from pumping can exit through the ports in the toe valve  8 , and out to the formation. 
     The ball  200  and dart  14  travel through each of a predetermined number of frac valves  6  until they reach the frac valve  6  to be opened. This is commonly the frac valve  6  closest to the toe end  10  of the wellbore, but need not necessarily be so. The upper collet  28  in the dart  14  is activated to be fixed in the engaged position by the time it lands on the seat  16  of the frac valve  6  be closed, so that the ball  200  and dart  14  are prevented from travelling through the seat  16  of the desired frac valve  6 . As described earlier, pressure begins to increase in the liner  2  uphole of the dart  14  and when the differential pressure across the dart  14  equals the opening pressure of the sleeve  16 , the sleeve  16  shifts to the open position, exposing the frac ports  18 . The sleeve  16  is commonly pressure balanced until a dart  14  lands on it. 
     After the first stage is stimulated, a second ball  200  and dart  14  can be pumped from surface. Again, the second ball  200  and dart  14  can travel through any predetermined number of frac valves  6  without opening them, and the indexing sleeve  22  is able to shift into the unengaged position each time. The upper collet  28  will only become fixedly engaged when it lands on restraint surface  52 . The upper collet  28  then again abuts against a shoulder  50  on the seat  16 . As applied fluid pressure uphole of the ball  200  increases, it shears the screws  20  holding the sleeve  16  in the closed position. The ball  200 , dart  14  and sleeve  16  shift exposing frac ports  18 . 
     In this way, while all darts  14  and all frac valves  6  are identical to one another, the initial location of the indexing sleeve along circumferential grooves  32  on the mandrel can be adjusted such that it hits restraint surface  52  and mandrel shoulder  54  after the dart  14  has passed through a predetermined number of frac valves  6 . 
     Each dart  14  can optionally be marked or identified to indicate the frac sleeve  6  it is meant to open. This can aid in ensuring that the darts  14  are deployed in the correct sequence. 
     With reference to  FIG. 10 a   , in one embodiment, the expandable uphole portion  24   a  of the mandrel  24  has a tapered inside diameter. When the ball  200  wedges into the taper, it expands the portion  24   a  radially outwardly to contact the I.D. of the sliding sleeve  16 . the contacting surfaces form a seal and also permit compressive forces to be transferred into the sliding sleeve  16 . this embodiment makes allowance for variation in diameters on both the sliding sleeve  16  and the dart mandrel  24 . 
     In another embodiment, depicted in  FIG. 10 b   , the expandable uphole portion  24   a  expands radially outwardly to contact the I.D. of the sliding sleeve  16 . the series of ridges  60  deform and generate a series of the circumferential seals. the deformed ridges also permit compressive loads to be transferred into the sliding sleeve  16 . 
     An embodiment that does not rely on expanding the uphole portion  24   a  mandrel  24  is illustrated in  FIG. 11 . In which a packing element may be used. when the dart  14  lands inside its mating frac sleeve  6 , an elastomeric ring  62  trapped between the upper collet  28  on the indexing sleeve  22  and mandrel shoulder  54 , expands due to the compressive load being transferred through it. the elastomeric ring  62  forms a seal between the uphole portion  24  of the mandrel  24  and the sliding sleeve  16  inside the frac valve  6 . 
     Regardless of the embodiment used, the seal formed between the dart  14  and the frac valve  6  isolates a thin walled downhole portion  24   b  of the mandrel  24  from collapse pressure during the frac, and from compressive forces that could cause buckling. Both of these features permit the inside diameter of the mandrel  24  to be optimized to the maximum diameter possible thereby giving the largest bore  40  flow area through the mandrel. 
     Another embodiment of the frac valve  6  and dart  14  is shown in  FIG. 14 . In this embodiment a single dart  14  is used to open multiple frac valves  6 . The sleeve  16  of the frac valve  6  in this embodiment preferably has a temporary no-go shoulder  56  installed thereon. As before, as the dart  14  is pumped through uphole frac valves  6 , the indexing sleeve  22  advances incrementally along circumferential groove  32 . When the upper collet  28  contacts the restraint surface  52  and mandrel shoulder  54  as shown in  FIG. 14 , the mandrel  24  of the dart  14  can no longer move further downhole relative to the indexing sleeve  22 . 
     Applied pressure generates a force from the upper collet  28  into sleeve  16 . This force shears the screws  20  holding the sleeve  16  in place. The ball  200 , dart  14  and sleeve  16  shift downhole, exposing the frac ports  18 . At this point, the temporary no-go shoulder  56  is aligned with an internal groove  58  formed on an inner surface of the frac valve outer body  44 . The radially outwardly engaged upper collet  28  pushes the temporary no-go-shoulder  56  radially outwardly into the groove  58 , thereby moving the temporary no-go-shoulder  56  out of the way such that it is no longer an obstacle. The dart  14  can now be pumped through the frac valve  6  and downhole until it lands on the next frac valve  6 , where the process is repeated. Multiple frac valves  6  containing the temporary no-go shoulder  56  may be installed and be opened by a single dart  14 . In this way, frac valves  6  along the liner  2  are opened generally from a heel  12  to toe  10  direction. 
     It should be noted that the indexing sleeve  22  in the dart  14  of embodiment of  FIG. 14  can still also be initially set to pass through one or more frac valves of the style of  FIG. 3  or  FIGS. 5 to 9 , and then eventually engage, open and pass through one or more frac valves  6  such as those of  FIG. 14 . 
     In certain sections of the well, as illustrated in  FIGS. 5 to 9 , frac valves  6  that open with a specific dart  14  may be used. In other segments of the same well it may be preferable to stimulate by opening a sequence of frac valves  6  with a single dart  14 , as in  FIG. 14 . When opening with the single dart  14 , the first frac valve  6  in the sequence to be opened will commonly be closest to the heel end  12  and the last frac valve  6  in the sequence to be opened will commonly be closest to the toe end  10 . Once opened, the frac valves  6  can be stimulated through simultaneously. 
     When all of the desired the frac valves  6  in the liner  2  have been opened and stimulated through, fluids from the formation can now be produced and flow into the well and into the liner  2  through the ports  18 . The balls  200  are lifted off their seats by this reverse fluid flow. 
     The ball can be manufactured from various materials, including phenolic, steel, aluminum or dissolvable composite. the mandrel can be manufactured from steel, aluminum or dissolvable composite. In a preferred embodiment, it is possible to construct both the ball  200  and dart  14  from a dissolvable material. In such cases, this eliminates the need to remove the dart  14  from the well. If the balls  200  are dissolvable, production flows through the large ID darts  14  and the darts  14  can stay in place. If the balls  200  are not dissolvable, dart flow back, as described below, occurs to flow the balls  200 , which push against a downhole end of their respective upstream darts  14 , and darts  14  uphole. 
     In a further option, an intervention tool can be run on coil tubing or pipe and can be used to either close or re-open frac valves  6  in the system. If a particular segment of the wellbore started to produce water for example, the adjacent frac valve  6  could be closed. If there was a desire to be able to return and re-frac a particular segment of the formation, frac valves  6  in that area that had previously been opened could be closed using an intervention tool. If a re-frac is desired, then the present system of frac valves  6  and darts  14  allow for the frac valves  6  to be opened or closed or re-opened at will. The intervention tool can be used if the ball  200  has dissolved and the dart  14  is still in place in the frac valve, in the case when a ball  200  and dart  14  have been flowed back to surface, or in the case if the ball  200  and the dart  14  have both dissolved. 
     Frac valves  6  that had been originally installed during the well construction process and had never been previously opened can now be opened using the present dart  14 , as it can be adjust to pass through any number of frac valves  6  uphole of the frac valve to be opened, without engaging or getting caught on any of the uphole frac valves  6 . Placement and arrangement of frac valves  6 , of either the style of  FIG. 3  or  FIG. 14 , is limitless. The present system provides an operator with full control over the stimulation and production operations of all stages of the wellbore. Since frac valves  6  can be opened, closed and reopened in any order, the operator is provided with an innovative flexibility. 
     The darts  14  can be flowed back to the surface when the frac job is complete and the well is being produced. In this embodiment a ball from a downstream dart  14 , travels upstream with flow of production fluid to rest on a downstream end of the mandrel  24  of an upstream dart  14 , thereby blocking flow through the inner bore  40  of the mandrel  24 . Pressure acting on a downhole end of the mandrel  24  and causes the indexing sleeve  22  to travel in reverse every time the dart  14  travelled upstream and passed through an upstream frac valve  16 . If nitrogen had been pumped during the frac, the nitrogen would assist in flowing the dart  14  back to the surface. Formation fluid or frac fluids would also assist in this process. If the ball  200  is manufactured from a dissolvable material, this can be beneficial if by chance the dart  14  became stuck at any point during flow back. 
     With reference to  FIG. 12 , in an optional embodiment of the present dart  14 , a hole  64  located in the mandrel  24  of the dart  14  can provide communication between the outer surface of the mandrel and inner surface of the mandrel. This permits fluid to flow past the dart in the event of a screen out. For the purposes of the present description, a screen out is a condition that occurs when the solids carried in a treatment fluid, such as proppant in a fracture fluid, cause a restricted flow area. This creates a sudden and significant restriction to fluid flow that causes a rapid rise in pump pressure. 
     Hole  64  also allows production fluids to flow to surface in the case of the use of balls  200  that are not dissolvable. The ball  200  from the downhole dart  14  would flow back and land against the lower end of the dart  14  located uphole. the hole  64  in the mandrel  24  would permit fluid to by-pass around the ball  200  and flow back to the surface. this feature can also be used on darts with a lock in place mechanism. 
     With reference to  FIG. 13 , this embodiment provides a mechanism by which the indexing sleeve  22  can be locked in place in the engaged position on the mandrel  24 . In this embodiment, the restraint surface  52  may be somewhat elongated such that when the dart  14  lands in its required frac valve, the indexing sleeve  22  continues to move relative to the mandrel  24  to shift the lower collet  30  also into the radially outwardly extended position, similar to the upper collet  28 . A snap ring  66  formed on the restraint surface would then snap into a groove  68  formed on a mating surface of the upper collet  28 , thus locking the indexing sleeve  22  in place relative to the mandrel  24 . 
     In other embodiments, not shown, any suitable means of preventing any axial movement of upper collet  28  and indexing sleeve  22  relative to the mandrel  24  would also serve as a locking mechanism, while maintaining the lower collet  30  in a radially outwardly expressed position. For example, engaging upper collet  28  against a further shoulder on the mandrel  24  to prevent relative movement of the mandrel  24  relative the indexing sleeve  22  would also be suitable and is encompassed by the scope of the present disclosure. 
     With reference to  FIG. 11 , in a further embodiment, a shear pin  48  located between the indexing sleeve  22  and mandrel  24  prevents pre-mature movement of the indexing sleeve  22  relative to the mandrel  24 . the shear pin  48  shears whenever the dart  14  reaches the first frac valve  6  in the liner. 
     The process described previously, introduces a novel method for well design and construction. It provides the operator with multiple options for completing the wellbore and also for the stages of stimulating and producing. The well may be completed with frac valves  6  that open independently from each other with individual darts  14  (as in the case of the frac valves  6  of  FIG. 3 ). The well also may be completed with frac valves  6  that open in conjunction with other frac valves  6  using a single dart  14  (as in the case of the frac valves  6  of  FIG. 14 ). 
     Alternatively both types of frac valves  6  can be used in the same liner  2  and be ordered in any configuration. Since each dart  14  is set to open particular valves and valve types, no valves can be prematurely opened by a dart  14 . Frac valves  6  may be opened for fracking and stimulation before initial production of the formation. After a given period of time, frac valves  6  that had not been previously been opened for fracking or stimulating can be opened and the formation can then be stimulated through them. 
     The present systems and tools introduce novel aspects to frac valve and dart construction as well as to stimulation and production operations. In the present disclosure a single dart  14  can be used to open one frac valve  6  or multiple frac valves  6 . A dart  14  can be adjusted to open a specific frac valve  6 , or combination of frac valves  6 . The innovative timing mechanism of the dart  14  permits the dart  14  to be set-up to travel through a desired number of frac valves and then engage and open a specific frac valve  6  or series of frac valves  6 . 
     The method and systems described herein permit access to an un-restricted near full bore well I.D. since the darts  14  are pumped down the well and not run on an intervention tool or other tubing deployed system that can restrict the ID of the liner  2 . Intervention tools can be used with the system to close, open or re-open specific or multiple frac valves at the operator&#39;s discretion. 
     While preferred embodiments of the disclosure have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the disclosure disclosed herein are possible and are within the scope of the disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations. The use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, and the like. 
     Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present disclosure. Thus, the claims are a further description and are an addition to the preferred embodiments of the present disclosure. The inclusion or discussion of a reference is not an admission that it is prior art to the present disclosure, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent they provide background knowledge; or exemplary, procedural or other details supplementary to those set forth herein.