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BACKGROUND INFORMATION 
     Field of the Disclosure 
       [0001]    Examples of the present disclosure relate to systems and methods for stimulating a well. 
       Background 
       [0002]    For purposes of communicating well fluid from surface and vice versa, the well may include tubing. The tubing typically extends downhole into a wellbore of the well for purposes of communicating well fluid from one or more subterranean formations through a central passageway of the tubing to the well&#39;s surface. However, there is a limit to how far downhole tubing can be pushed before friction and buckling becomes excessive. As a consequence, this may limit the length of the well where a down hole tool may be conveyed, limiting the ability to treat or intervene in extended or long reach wells. 
         [0003]    Hydraulic fracturing is performed by pumping fluid into a formation at a pressure sufficient to create fractures in the formation. When a fracture is open, a propping agent is added to the fluid. The propping agent, e.g. sand or ceramic beads, remains in the fractures to keep the fractures open when the pumping rate and pressure decreases. 
         [0004]    In conventional applications, sand and gravel from the formation enters the annulus between an outer diameter of a tool and an inner diameter of the tubing. The propping agent in the annulus prevents the string and injection assembly from moving to the next target zone or to the surface. 
         [0005]    Accordingly, needs exist for system and methods for fracturing utilizing a dart to pull or push tubing further down a well, while controlling pressure and fluid through an outer diameter and an inner diameter to activate a tool to perform treatment at a first valve, reset the tool, move the tool, and reactivate the tool to perform treatment over a second valve. 
       SUMMARY 
       [0006]    Embodiments disclosed herein describe fracturing methods and systems, wherein pressure differentials and fluid flow rates may be utilized to stimulate multiple zones, sleeves, or ports with the same tool and different conveying method (i.e.: Coiled Tubing, Stick Pipe). 
         [0007]    In embodiments, a hole may be run with tubing. A tool with a dart may be positioned within the tubing. Fluid may be pumped in an annulus between the tool and the tubing applying pressure on the dart to push and/or pump the tool further down the well. Responsive to the fluid being applied in the annulus to the dart, fluid positioning below a first end of the dart may flow into the inner diameter of the tool through a passageway within the dart and an open port on a first end of the tool. 
         [0008]    Responsive to the tubing being pushed and/or pumped to a desired depth, a fluid flow rate through the inner diameter of the tool may be increased. This may close a check valve causing the pressure within the inner diameter of the tool to increase. The increase in pressure within the inner diameter of the tool pushes a piston to move and shear off the dart. Furthermore, when the piston moves, a shifting profile on the tool may be activated. In embodiments, the shifting profile may be permanently opened when activated. 
         [0009]    Next, the tool may be moved towards a proximal end of the tubing until the activated shifting profile engage with a locking or female profile (referred to hereinafter individually and collectively as “female profile”) positioned on the inner diameter of the casing. When the shifting profile is aligned with the female profile, a force differential may occur, allowing monitoring devices and/or gauges at the surface to remotely indicate that the shifting profile engaged with the female profile. 
         [0010]    After the force differential occurs, fluid may flow through the inner diameter of the tool until the check valve shifts to activate the tool. When the tool is activated, a seal packer may expand to assist in creating a piston force on a valve sleeve. This piston force may force the valve sleeve to move downward to expose a valve port, and to align the valve sleeve with a stimulation port through the casing. Fluid flow within the annulus may be increased, and treatment may be performed over the outer diameter of the tool and out to the geological formation. 
         [0011]    In embodiments, during treatment of a zone, it may be required to maintain pressure on the inner diameter of the tool to keep the seal packer activated to maintain the seal for treatment. When treatment of the zone is complete, pressure on the inner diameter of the tool is bleed off, which may allow the tool to reset. The tool may be reset by moving the tool towards a proximal end of the tubing, disengaging the shifting profile from the female profile. At this time, debris within the tool and well may be cleaned via circulation (i.e.: reverse or direct circulation). Once done, the procedure may repeat, and the next valve may be opened and treated. In embodiments, the shifting profile and the female may limit or restrict the downward movement of the tool. 
         [0012]    In embodiments, multiple valve or ports may be installed on a casing that are positioned at a predetermined distance apart. This predetermined distance will allow for future re-fracing pre-spaced out sealing tools to be conveyed to the well, isolating various opened ports simultaneously in a string in order to eliminate cross flow from secondary open ports. 
         [0013]    In embodiments, a locator and multiple packers may be positioned below and above the valve. Further up the string, a new packer may seal off the ports in a pre-installed valve. This may eliminate or reduce communication in the formations between the zones or stages. When one sleeve has been refractured, fluid flow may be stopped. Then, the tool may be reset and moved to the next valve until the force differential occurs to indicate the correct placement of the tool. 
         [0014]    These, and other, aspects of the invention will be better appreciated and understood when considered in conjunction with the following description and the accompanying drawings. The following description, while indicating various embodiments of the invention and numerous specific details thereof, is given by way of illustration and not of limitation. Many substitutions, modifications, additions or rearrangements may be made within the scope of the invention, and the invention includes all such substitutions, modifications, additions or rearrangements. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0015]    Non-limiting and non-exhaustive embodiments of the present invention are described with reference to the following figures, wherein like reference numerals refer to like parts throughout the various views unless otherwise specified. 
           [0016]      FIG. 1  depicts a system for stimulation a well, according to an embodiment 
           [0017]      FIG. 2  depicts a system for stimulation a well, according to an embodiment 
           [0018]      FIG. 3  depicts a system for stimulation a well, according to an embodiment 
           [0019]      FIG. 4  depicts a system for stimulation a well, according to an embodiment 
           [0020]      FIG. 5  depicts a system for stimulation a well, according to an embodiment 
           [0021]      FIG. 6  depicts a system for stimulation a well, according to an embodiment. 
           [0022]      FIG. 7  depicts a method for stimulating a well, according to an embodiment. 
       
    
    
       [0023]    Corresponding reference characters indicate corresponding components throughout the several views of the drawings. Skilled artisans will appreciate that elements in the figures are illustrated for simplicity and clarity and have not necessarily been drawn to scale. For example, the dimensions of some of the elements in the figures may be exaggerated relative to other elements to help improve understanding of various embodiments of the present disclosure. Also, common but well-understood elements that are useful or necessary in a commercially feasible embodiment are often not depicted in order to facilitate a less obstructed view of these various embodiments of the present disclosure. 
       DETAILED DESCRIPTION 
       [0024]    In the following description, numerous specific details are set forth in order to provide a thorough understanding of the present embodiments. It will be apparent, however, to one having ordinary skill in the art, that the specific detail need not be employed to practice the present embodiments. In other instances, well-known materials or methods have not been described in detail in order to avoid obscuring the present embodiments. 
         [0025]      FIG. 1  depicts a fracturing system  100 , according to an embodiment. System  100  may include tool  110  and casing  120 , wherein there may be an annulus  130  between an outer diameter of tool  110  and an inner diameter of casing  120 . 
         [0026]    Tool  110  may include a hollow chamber extending from a proximal end of tool  110  to a distal end of tool  110 . The distal end of tool  110  may include port  112 . Port  112  may have a smaller diameter than the inner diameter of tool  110  and may be configured to control fluid flowing through the inner diameter of tool  110 . Additionally, port  112  may be configured to control pressure levels within the inner diameter of tool  110 . Tool  110  may include a dart  140 , coupling mechanisms  148 , check valve  150 , piston sleeve  160 , ledge  170 , locking mechanism  180 , and shifting profile  190 . 
         [0027]    Dart  140  may be removably coupled to a distal end of tool  110 , and be configured to pull and/or push conveying tubing  112  and tool  110  downwell. In embodiments, dart  140  may be configured to be coupled with any type of tool, tubing, device, etc. Dart  140  may have a larger diameter than the second end of tool  110 , such that an inner circumference of dart  140  is positioned adjacent to an outer circumference of tool  110 . Dart  140  may include a first end  142 , second end  144 , and projections  146 , wherein there may be a hollow chamber extending between first end  142  and second end  144 . 
         [0028]    First end  142  may be configured to be positioned over a distal end of tool  110 . Projections  146  may be rubber extensions extending across annulus  130 , wherein projections  146  are configured to receive fluid flowing through annulus  130 . In embodiments, there may be a limit as to how far down well tubing  112  may be pushed due to buckling. To increase the distance over which tubing  112   120  may be pulled and/or pushed downward, fluid flowing through annulus  130  may cause dart  140  to pull and/or push tubing  112  further down well. Responsive to the fluid flowing below second end  144  of dart  140 , the fluid may enter the hollow chamber within dart  140 , and exit dart  140  into tool  110  via port  112 . This fluid may then flow out of the proximal end of tool  110 . In embodiments, dart  140  may be configured to be sheared away from tool  110  based on pressure increase within the inner diameter of tool  110 . 
         [0029]    However, in other embodiments, dart  140  may be sheared from tool in different methods. For example, dart  140  may be sheared from tool  110  by increasing the pressure on the outer diameter and restricting the movement of tool  110 . This pressure may create an increasing downward force. Responsive to the pressure on the outer diameter of dart  140  increasing past a threshold, dart  140  may be sheared from tool  110 . In further embodiments, a restriction, projector, ledge, edge may be installed within the well or casing  120 . When dart  140  passes through the restriction, the restriction may release dart  140  from tool  110 . Other embodiments may utilize a ball to release dart  140 , wherein the ball may be dropped within the well causing a sleeve to shift to release dart  140 . 
         [0030]    Furthermore, embodiments may include drag blocks or friction devices that are configured allow dart  140  to be removed from a well. The drag blocks or friction devices may be configured to interface with projections  146 , wherein projections  146  may be comprised of rubber. Responsive to moving dart  140  towards the proximal end of the well, rubber projection  146  may be sheared from dart  140 . One skilled in the art may appreciate the drag blocks or friction devices may be used in combination with J-Slots. 
         [0031]    Check valve  150  may be positioned within the inner diameter of tool  110 , and be configured to move in a linear axis in parallel to the longitudinal axis of tool  110 . Check valve  150  have a smaller diameter than that of tool  110 , such that fluid may flow between check valve  150  and the inner diameter of tool  110 . Check valve  150  may have a first end having a first diameter and a second end having a second diameter. The first diameter may be smaller than a diameter of port  112 , and the second diameter may be larger than the diameter of port  112 . In a first orientation, the second end of check valve  150  may be configured to be positioned away from the port  112  to allow fluid to flow across port  112 . Alternatively, in a second orientation, a second end of check valve  150  may be configured to be positioned adjacent to port  112  to restrict, limit, inhibit, etc. fluid from flow across port  112  and/or to increase the pressure within tool  110 . Accordingly, check valve  150  may be a device allowing fluid to flow through port in both linear directions. By allowing fluid flow in multiple directions, the fluid may flow over tool  110  to clean areas of sand or debris within tool  110 , if required. Furthermore, check valve  150  may eliminate the need for a toe sub, as embodiments are able to take return fluid through the inner diameter of tool  110 . 
         [0032]    In embodiments, responsive to increasing fluid flow through the inner diameter of tool, the second end of check valve  150  may move from the first orientation to the second orientation to close check valve  150 . When check valve  150  is closed, pressure within the inner diameter of tool  110  may increase to push piston sleeve  160  to shear dart  140  off tool  110 . In embodiments, responsive to decreasing pressure through the inner diameter of tool  110 , check valve  150  may move from the second orientation to the first orientation. This may cause the second end of check valve  150  to move away from port  112  to open check valve  150 . However, one skilled in the art may appreciate that check valve  150  may be opened or closed in multiple manners, such as dropping a ball to open or close check valve  150 . 
         [0033]    Piston sleeve  160  may be positioned on an outer diameter of tool  110 , and may be positioned between shifting profile  190  and dart  140 . Piston sleeve  160  may be configured to move along a linear axis in parallel to the longitudinal axis based on a pressure level within the inner diameter of tool  110 . Piston sleeve  160  may include first end  162  with outcrop  163 , and second end  164 . When check valve  150  is closed, a first end  162  and outcrop  163  of piston sleeve  160  may overhang ledge  170 . The first end  162  of piston sleeve  160  may be configured to suppress shifting profile  190  from expanding. When check valve  150  is opened, first end  162  of piston sleeve  160  may slide to not cover ledge  170 . This may allow locking mechanism  180  to expand. When check valve  150  is initially opened, second end  164  may be positioned adjacent to port  112 . Responsive to closing check valve  150  and moving piston sleeve  160  towards the distal end of tool  110 , causing second end  164  to apply force against and shear dart  140  from tool  110 . 
         [0034]    Ledge  170  may be a sidewall positioned on the outer diameter of tool  110 . By positioning outcrop  163  and/or first end  162  of piston sleeve  160  over ledge  170 , the outward movement of shifting profile  170  and/or locking mechanism  180  may be suppressed. 
         [0035]    Locking mechanism  180  may be a device that is configured to retract, compress, extend, elongate, etc. For example, locking mechanism  180  may be a spring. Locking mechanism  180  is configured to move shifting profile  190  responsive to locking mechanism  180  being extended or compressed. Locking mechanism  180  may be extended or compressed based on the positioning of piston sleeve  160 . When piston sleeve  160  is positioned over ledge  170 , an inner surface of piston sleeve  160  may restrict the outward movement of locking mechanism  180 , such that locking mechanism  180  remains compressed. When first end  162  of piston sleeve  160  does not extend over ledge  170 , locking mechanism  180  may be elongated. 
         [0036]    Shifting profile  190  may be a device that is configured to allow tool  110  to move along an axis parallel to the longitudinal axis of tool  110  while in a first position, and restrict the movement of tool  110  in a second position. 
         [0037]    In the first position, locking mechanism  180  may be compressed and an outer surface of shifting profile  190  may be aligned with an outer diameter of tool  110 , such that the outer surface of shifting profile  190  is positioned away from an inner diameter of casing  120 . In the second position, locking mechanism  180  may be extended and an outer surface of shifting profile  190  may extend across annulus  130  and be embedded within a female profile on the inner diameter of casing  120 . Responsive to interfacing shifting profile  190  with the female profile, tool  110  may be secured in place. However, a sufficient upward force on tool  110  may disengage shifting profile  190  from the female profile 
         [0038]    Tubing  112  may be a pipe, coil, etc. extending from a surface level into a geological formation. Tubing  112  may be configured to be pulled and/or pushed into the desired depth within the well bore via dart  140 . 
         [0039]    Casing  120  may include a profile that includes a female profile, indention, depression, etc., which may be configured to receive shifting profile  190  to secure tool  110  in place. Casing  120  may be installed in a well before tool  110  is run into the well. Furthermore, casing  120  may include channels, passageways, and conduits extending from a first location on an inner diameter of casing  120  to a second location on the inner diameter of casing  120  to control, maintain, or change the pressure on different sides of a sealing packer element on the tool. Casing  120  may also include channels, passageways, and conduits extending through the casing  120  to perform treatment out of the geological formation. 
         [0040]      FIG. 2  depicts system  100 , according to an embodiment. Elements depicted in  FIG. 2  may be substantially the same as those described above. For the sake of brevity an additional description of those elements is omitted. 
         [0041]    As depicted in  FIG. 2 , a hole may be run with tubing  112 . Due to a limit to how far tubing  112  may be pushed down due to friction, buckling, etc., to increase the amount of distance tubing  112  is displaced into well bore, fluid may be pumped through annulus  130 . This fluid may pull/push dart  140 , tool  110 , and tubing  112  down the well. Because check valve  150  may be in an open position, when the fluid flows past dart  140 , the fluid may flow into the inner diameter of dart  140  and tool  110  via port  142 . This fluid may return upward through the well via tool  110  and tubing  112 . 
         [0042]      FIG. 3  depicts system  100 , according to an embodiment. Elements depicted in  FIG. 3  may be substantially the same as those described above. For the sake of brevity an additional description of those elements is omitted. 
         [0043]    In  FIG. 3 , tubing  112  may reach a desired depth, and fluid flowing through an inner diameter of tool  110  may increase. The increase in fluid rate may force check valve  150  to move linearly towards the distal end such that the second end of check valve  150  is positioned adjacent to and covering port  112 . By closing check valve  150 , the pressure within the inner diameter of tool  110  may increase. The increase in pressure may cause piston sleeve  160  to move and shear off dart  140 . The shearing of dart  140  may separate dart  140  from tool  110 . 
         [0044]    When piston sleeve  160  moves, first end  162  of piston sleeve  160  may traverse ledge  170 . Responsive to first end  162  traversing ledge  170 , locking mechanism  180  may expand and shifting profile  190  may be unlocked. When shifting profile  190  is unlocked, shifting profile  190  may extend across annulus  130 . Furthermore, when shifting profile  190  is unlocked, packer  310  may be extended across annulus  130  at a pre-defined pressure. 
         [0045]      FIG. 4  depicts system  100 , according to an embodiment. Elements depicted in  FIG. 4  may be substantially the same as those described above. For the sake of brevity an additional description of those elements is omitted. 
         [0046]    As depicted in  FIG. 4 , an inner diameter of casing  120  may include a female profile  410 , wherein female profile  410  may be a depression, groove, indentation, etc. Female profile  410  may be configured to receive portions of shifting profile  190  to secure tool  110  in place. Responsive to tool  110  being moved along a linear path towards the proximal end of casing  120 , shifting profile  190  may engage with and interface with female profile  410 . When shifting profile  190  interfaces with female profile  410 , a force differential may occur at a surface to indicate that the shifting profile is engaging with female profile  410 . 
         [0047]    Furthermore, due to a lack of pressure differential in favor of inner diameter of tool  110 , check valve  150  may move away from port  112  and be in the open position. 
         [0048]      FIG. 5  depicts system  100 , according to an embodiment. Elements depicted in  FIG. 5  may be substantially the same as those described above. For the sake of brevity an additional description of those elements is omitted. 
         [0049]    In  FIG. 5 , fluid may flow through the inner diameter of tool  110 , which may close check valve  150 . Responsive to closing check valve  150 , packer  310  may be activated. When packer  310  is activate, portions of packer  310  may extend across annulus  130  and be positioned against the inner diameter of tubing  112 . This may segregate the annulus  130  to include a lower end  132  and an upper end  134 . 
         [0050]    In embodiments, packer  310  is maintained in the activated state due to a predetermined pressure level inside tubing  112 . 
         [0051]    Additionally, as depicted in  FIG. 5 , system  100  may also include a stimulation port  520  and valve sleeve  530 . Stimulation port  520  may be an orifice extending through casing  120 , wherein stimulation port  520  is configured to dispense fluid flowing over the annulus  130  into the geological formation. 
         [0052]    Valve sleeve  530  may be a sleeve positioned adjacent to the inner diameter of casing  120 . Valve sleeve  530  may be configured to move in a direction parallel to the longitudinal axis of casing  120 . Valve sleeve  530  may include a valve port that is configured to align with stimulation port  520  to be in an open position. 
         [0053]    In the open position, fluid may flow out or in to stimulation port  520 . However, if valve sleeve  530  is misaligned with stimulation port  520 , a sidewall of valve sleeve  530  may not allow the fluid to flow outside of annulus  130 . Furthermore, valve sleeve  530  may include a locking mechanism  540  that is configured to interface with a locking element within tubing  112 . Responsive to interfacing locking mechanism  530  with the locking element, the valve port and the stimulation port  520  may remain in the open position. 
         [0054]    Furthermore, system  100  may not require an atmospheric chamber, and valve sleeve  530  may not be activated by internal pressure alone. However, when packer  310  is activated, a pressure port  510  positioned below valve sleeve  530  creates a pressure differential between the lower annulus  132  and the upper annulus  134 . When packer  310  is activated, valve sleeve  530  becomes a piston being able to shift open based on the pressure differential caused by packer  310  separating the upper and lower sections of annulus  130 . Accordingly, without packer  310  being activated, the pressure differential may not occur and the sleeves may not open accidently, inadvertently, etc. 
         [0055]    In embodiments, a benefit of a pressure activated sleeve system  100  is that one is able to pressure test the outer casing  120  for pressure integrity without a toe sub or without opening the sleeves during the process. Then, the well may be treated as required, sleeve by sleeve. Utilizing embodiments, a pressure differential may be created, and shift a sleeve without pulling on a tool string or tubing  112  to open or close the ports. By setting the tool  110  and providing pressure on the annulus  130 , embodiments are able to open a specific port where the tool  110  is set. Then, embodiments may be treated over the tool  110  or tubing  112  into the completion. 
         [0056]      FIG. 6  depicts system  100 , according to an embodiment. Elements depicted in  FIG. 6  may be substantially the same as those described above. For the sake of brevity an additional description of those elements is omitted. 
         [0057]    In  FIG. 6 , when packer  310  is expanded, tool  110  creates a comparted annulus above and below the packer  310 , when pressure is applied above the packer  310 , a piston force on valve sleeve  530  is achieved to slide valve sleeve  530 . Valve sleeve  530  may move towards the distal end of casing  120  so that valve port  610  is aligned with stimulation port  520 . In embodiments, coupling mechanisms, such as shear screws, collets, detents, etc., may be configured to maintain valve sleeve  530  in a closed position before packer  310  is expanding separating annulus into the lower annulus  132  and the upper annulus  134 . The coupling mechanisms may be configured to keep valve sleeve  530  from opening when elements are positioned within annulus  130 . However, once tool  110  is set and packer  310  is expanded, the pressure increase on the upper annulus  134  that creates the piston force becomes greater than the coupling force of the coupling mechanisms. This may allow for the coupling mechanisms to be sheared, and valve sleeve  530  to be opened. 
         [0058]    Responsive to aligning valve port  610  with stimulation port  520 , fluid may flow from or to the annulus  130 . Fluid flowing in annulus  130  may be increased, and treatment may be performed over the outer diameter of tool  110  and out into the geological formation. Additionally, when valve sleeve  530  moves, locking mechanism  540  may be engaged with the locking element. 
         [0059]    It is desired that pressure is maintained on the inner diameter of packer  310  to keep packer  310  activated, keeping the seal for treatment. However, when treatment is completed, pressure on the inner diameter of tool  110  may bleed off, which may reset the tool  110 . When tool  110  is reset, check valve  150  may open, closing packer  310 . After tool  110  is reset, debris may be removed from around tool  110  and in the well. Upward force may then be applied to disengage shifting profile  150  from female profile  310 . Tool  110  may then be pulled towards the proximal end of casing  120 , align with a subsequent female profile, and treat a subsequent valve. Accordingly, tool  110  may be utilized to treat multiple valves within a string. 
         [0060]    In embodiments, multiple valves or ports may be installed on casing that are positioned at a predetermined distance from each other. This predetermined distance will allow for packer sealing tools to be mounted on the future re fracturing string to eliminate cross flow from secondary open valves, i.e.: a valve or group of valves above or below the valve being operated. In embodiments, a locator and multiple packers may be positioned below and above a valve. Further up the string, a new packer may seal off the ports in a pre-installed valve. This may eliminate or reduce the flow out of the valves due to communication in the formation between the zones or stages. When one sleeve has been refractured, the tool may be reset and move to the next valve and operation repeated. 
         [0061]      FIG. 7  depicts a method  700  for stimulating a well. The operations of method  700  presented below are intended to be illustrative. In some embodiments, method  700  may be accomplished with one or more additional operations not described, and/or without one or more of the operations discussed. Additionally, the order in which the operations of method  700  are illustrated in  FIG. 7  and described below is not intended to be limiting. Furthermore, the operations of method  700  may be repeated for subsequent valves or zones in a well. 
         [0062]    At operation  710 , fluid may flow within an annulus between an outer diameter of a tool and an inner diameter of a tubing to interact with a dart to pull and/or push the tubing downward. 
         [0063]    At operation  720 , fluid may flow through an inner diameter of tool from a proximal end of the tool towards the distal end of the tool. The fluid flowing through the tool may cause a check valve to close. Responsive to the check valve closing, the pressure within the inner diameter of the tool may increase. 
         [0064]    At operation  730 , due to the increase in pressure within the inner diameter, a piston sleeve may slide towards the distal end of the tool shearing off the dart. Additionally, responsive to the piston sleeve sliding, a shifting profile may be unlocked. 
         [0065]    At operation  740 , the tool may slide towards the proximal end of the tubing until the shifting profile interfaces with a female profile within the tubing. While the tool is sliding towards the proximal end of the tubing, the fluid flow rate through the inner diameter of the tool may decrease, and the check valve may be opened. 
         [0066]    At operation  750 , the fluid flow rate through the inner diameter of the tool may increase to close the check valve and activate the packer. Followed by pumping fluid in annulus, this may cause the pressure within the annulus to increase. 
         [0067]    At operation  760 , the increase in pressure may cause a valve sleeve to slide towards the distal end of the tubing to align a stimulation port with a valve port. 
         [0068]    At operation  770 , when the stimulation port and the valve port are aligned, treatment may be performed within the geological formation. 
         [0069]    Reference throughout this specification to “one embodiment”, “an embodiment”, “one example” or “an example” means that a particular feature, structure or characteristic described in connection with the embodiment or example is included in at least one embodiment of the present invention. Thus, appearances of the phrases “in one embodiment”, “in an embodiment”, “one example” or “an example” in various places throughout this specification are not necessarily all referring to the same embodiment or example. Furthermore, the particular features, structures or characteristics may be combined in any suitable combinations and/or sub-combinations in one or more embodiments or examples. In addition, it is appreciated that the figures provided herewith are for explanation purposes to persons ordinarily skilled in the art and that the drawings are not necessarily drawn to scale. For example, in embodiments, the length of the dart may be longer than the length of the tool. 
         [0070]    Although the present technology has been described in detail for the purpose of illustration based on what is currently considered to be the most practical and preferred implementations, it is to be understood that such detail is solely for that purpose and that the technology is not limited to the disclosed implementations, but, on the contrary, is intended to cover modifications and equivalent arrangements that are within the spirit and scope of the appended claims. For example, it is to be understood that the present technology contemplates that, to the extent possible, one or more features of any implementation can be combined with one or more features of any other implementation.

Summary:
Embodiments disclosed herein describe fracturing methods and systems, wherein pressure differentials and fluid flow rates may be utilized to stimulate multiple zones, sleeves, or ports with the same tool.