Patent Publication Number: US-2023132593-A1

Title: Downhole telemetry during fluid injection operations

Description:
TECHNICAL FIELD 
     The disclosure generally relates to the field of downhole fluid injection operations and to well system telemetry. 
     BACKGROUND 
     Real-time feedback of operational properties, such as fluid pressure during hydraulic fracturing, is important for optimizing the fracturing process. Hydraulic fracturing operations entail applying high level fluid pressures within a cased or uncased wellbore conduit and into perforations through the wellbore wall into a formation. The turbulent operating environment and resultant acoustic interference limits practicable wireless telemetry options. The downhole noise may render the signal strength of traditional structural-acoustic telemetry, such as via electro-acoustic transducers, insufficient. Economical wellbore construction may preclude the use of electromagnetic telemetry equipment, such as insulated gaps, through different wellbore stages. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Embodiments of the disclosure may be better understood by referencing the accompanying drawings. 
         FIG.  1    is a high-level block diagram depicting a well system configured for hydraulic fracturing and in which fluid pulse telemetry may be implemented, in accordance with various embodiments. 
         FIG.  1 A  is a cross-sectional diagram illustrating a wellbore system including a plug apparatus coupled to a coiled tubing, in accordance with various embodiments. 
         FIG.  1 B  is a cross-sectional diagram illustrating a wellbore system including a plug apparatus, in accordance with various embodiments. 
         FIG.  1 C  is a cross-sectional diagram illustrating a wellbore system including a plug apparatus, in accordance with various embodiments. 
         FIG.  2    is a cross-section diagram illustrating a fluid signal generator deployed within a wellbore in accordance with various embodiments. 
         FIG.  3    is a cross-section diagram illustrating a fluid signal generator deployed within a wellbore in accordance with various embodiments. 
         FIG.  4 A  shows a graph illustrating data generated based on changes in pressure generated by a fluid signal generator, according to various embodiments. 
         FIG.  4 B  shows a graph illustrating data generated based on changes in fluid flows generated by a fluid signal generator, according to various embodiments. 
         FIG.  5 A  is a cross-section diagram illustrating a fluid signal generator deployed within a wellbore in accordance with various embodiments. 
         FIG.  5 B  shows a graph illustrating data generated based on changes in pressure generated by a fluid signal generator, according to various embodiments. 
         FIGS.  5 C and  5 D  illustrate an end view of a siren according to various embodiments. 
         FIG.  6 A  illustrates a side view of a fluid vortex incorporated into a fluid signal generator according to various embodiments. 
         FIG.  6 B  shows a graph illustrating data generated based on changes in fluid flow rates generated by a fluid signal generator, according to various embodiments. 
         FIGS.  6 C and  6 D  illustrate a cutaway view of a fluid vortex device, according to various embodiments. 
         FIG.  7    is a flow chart illustrating a method for providing fluid signal generation as part of a wellbore treatment operation, according to various embodiments. 
         FIG.  8    illustrates a block diagram of an example computer control system that may be employed to practice the concepts, methods, and techniques disclosed herein, and variations thereof 
         FIG.  9    illustrates a block diagram of an example computer control system that may be employed to practice the concepts, methods, and techniques disclosed herein, and variations thereof. 
     
    
    
     DESCRIPTION OF EMBODIMENTS 
     The description that follows includes example systems, methods, techniques, and program flows that embody embodiments of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. In other instances, well-known instruction instances, protocols, structures and techniques have not been shown in detail in order not to obfuscate the description. The term “uphole” in examples used this disclosure refers to the general direction relative to the surface or wellhead of a borehole, wherein a uphole direction is a direction within the borehole that leads to the surface or the wellhead of the wellbore. The use of the term “uphole location” may be used to refer to a position along the axis of the borehole that is closer to the surface or the wellhead of the borehole compared to another location along the borehole. The term “downhole” in examples used this disclosure refers to the general direction relative to a terminus or end of a borehole, wherein a downhole direction is a direction within the borehole that leads to the terminus or end of the borehole. The use of the term “downhole location” may be used to refer to a position along the axis of the borehole that is closer to the terminus or end of the borehole compared to another location along the borehole. 
     Overview 
     Disclosed embodiments include devices, components, systems, and methods for providing communications across well system components during wellbore fluid injection operations using fluid-acoustic wireless telemetry. Telemetry system utilized to provide communications, such as data transmissions, between devices located within a wellbore and/or between devices located within a wellbore and devices outside the wellbore may include wired and/or wireless systems. Versions of structural-acoustic wireless telemetry system send the wireless signals utilized for communications through vibrations in the steel tubing. Versions of fluid-acoustic wireless telemetry send the wireless signal that are utilized for communication through vibrations in a fluid, such as a column of fluid being utilized to perform a fluid treatment process, such as a fracturing process, on a wellbore. 
     Disclosed embodiments may include devices, components, systems, and methods for controlling aspects of fluid injection operations such as setting and modifying injection fluid flow rate and injection fluid pressure using well system telemetry that leverages aspects of high-pressure downhole fluid injection operations such as hydraulic fracturing injection and gravel packing operations. In some embodiments, a well system configured to implement fluid injection operations may include a fluid conduit within a wellbore and a system of pumps that that apply dynamically controllable pressure within the wellbore to generate a pressurized fluid column within the wellbore, which is provided and maintained within the wellbore for the purpose of fracturing the formation at some locations or locations surrounding the wellbore. In various embodiments, the fracturing procedure involves providing an injection fluid to the wellbore in a single flow path, the single flow path having a first end at the surface and ending at the toe of the wellbore, the injection fluid provided from the surface and in a direction downhole without the need for a return path to the surface for the injection fluid. In various embodiments, the pressurized fluid column is a solids-free stimulation fluid provided so that the stimulation fluid can flow into the formation without fracturing. 
     An injection pressurization plug is installed within the wellbore below the pressurized fluid column and above a previously treated or otherwise non-pressurized portion of the wellbore. The injection pressurization plug is configured to block flow of the pressurized fluid column and may include a plug body and an outer pressure seal disposed on an outer cylindrical surface of the plug body. The plug body with the outer pressure seal are configured to provide a contact pressure barrier with an inner surface of a wellbore to block flow of the pressurized fluid column within the wellbore. A fluid signal generator may be disposed within the plug body and configured to transmit fluid signals through the pressurized fluid column. The fluid signals may be generated by controllably opening and closing a fluid flow channel within the pressurization plug, the fluid flow channel extending from the pressurized fluid column to an unpressurized side of the plug. In some embodiments, the plug body may comprise a complete plug apparatus or part of a plug apparatus such as a frac ball. 
     A well system configured to implement fluid injection operations may also include an acoustic receiver configured to receive and decode the fluid signals. An injection controller may be communicably coupled to the acoustic receiver and may be configured to generate fluid injection control instructions based, at least in part, on the decoded fluid signals. The injection controller may comprise a flow rate controller communicatively coupled to a fluid injection system, said flow rate controller configured to determine at least one of injection flow rate of the fluid injection system and an injection fluid pressure of the fluid injection system based, at least in part, on the decoded fluid signals. 
     Example Illustrations 
       FIG.  1    is a block diagram depicting a well system  100  configured to implement fluid injection and treatment operations in accordance with various embodiments. Well system  100  includes sub-systems, devices, and components configured to implement multi-stage fluid injection operations, such as hydraulic fracturing operations or gravel packing operations, within a wellbore  104 . In the embodiment depicted in  FIG.  1   , well system  100  includes an injection rig  130  positioned over or proximate to the wellhead  102  of the wellbore  104  at surface  101 . Well system  100  further includes an injection system  150  configured to mix and provide to the injection rig  130  an injection fluid for use in the fracturing and/or fluid treatment operations to be performed on wellbore  104 , and a monitoring/control system  140  to communicate with one or more downhole apparatus, and in various embodiments to provide control over the fluid injection operations being performed on wellbore  104 , as further described below. 
     Wellbore  104  in the depicted embodiment of  FIG.  1    comprises the cylindrical conduit as being a casing string. In some embodiments, wellbore  104  may comprise a conduit within a different type of wellbore treatment string, or may be an uncased, open borehole. In some embodiments, wellbore  104  may comprise coiled tubing that sits within a cased hole. Injection rig  130  includes components for configuring and controlling deployment of fluid injection components within wellbore  104 . For example, injection rig  130  may be configured to deploy one or more plug apparatuses, such as plug apparatuses  112  and  114 , sequentially at specified respective locations within wellbore  104 . Plug apparatuses  112  and  114  may be positioned within wellbore  104  using pump-down operations, in which a given plug apparatus may be coupled to a wireline bottom hole assembly (not depicted) that includes a setting tool as well as the plug apparatus. In various embodiments, use of a slickline, jointed tubing, or coiled tubing may also be used for placing the plug apparatus at the desired location(s) along the wellbore. In alternative embodiments, the plug apparatus may be fixedly attached to the formation through the use of cement, slips, swellable packer, or a chemically reacting packer. For hydraulic fracturing operations, the bottom hole assembly that deploys the plug apparatuses may also include a perforating gun (not depicted). During a perforation phase of each hydraulic fracturing operation, the perforating gun is positioned at a desired location within the wellbore  104 , and once located, fires a charge or multiple charges arranged to perforate the metallic casing, cement sheath, and/or proximate formation material at the desired location or locations along wellbore  104 . The perforations within the resultant perforation cluster(s) result in small fractures in the rock, typically shale, proximate wellbore  104 . In the depicted embodiment, three distinct sets of perforation clusters— 110 A,  110 B, and  110 C—correspond to one of three distinct hydraulic fracturing cycles in which perforation clusters  110 A,  110 B, and  110 C may in some embodiments be generated sequentially, with cluster  110 A generated furthest from the wellhead  102 , cluster  110 B generated closer to the wellhead  102  compared to cluster  110 A, and wherein cluster  110 C generated at a location along the borehole closest to the wellhead. 
     Injection rig  130  is configured to implement an injection phase, sometimes referred to as stimulation procedure for hydraulic fracturing, in which fluid is pumped at high pressure down the typically cased or otherwise lined wellbore  104  to form a fluid column  106  above the last (most uphole) blockage within wellbore  104 . For example, the first fluid injection phase following creation of perforation cluster  110 A, and prior to creation of clusters  110 B and  110 C and the setting of plug apparatuses  112  and  114 , may include pumping some form of treatment fluid up to the end  107  of wellbore  104 . The fluid path is block by the end  107  of wellbore  104 , resulting in a high-pressure fluid column that penetrates through the holes within perforation cluster  110 A and into formation within downhole strata  105 . The fluid penetration results in fracturing of formation rock material. Following an initial hydraulic fracturing operation at or near the end  107  of the wellbore, subsequent fracturing operations are implemented by setting plugs, such as plug apparatus  112  and  114 , to form the wellbore blockages configured to withstand sufficient fluid pressure for injection fracturing for each subsequent perforation cluster while preventing perforation cluster  110 A from being exposed to the fluid pressure applied in these subsequent fracturing operations. Typical fluid pressures for hydraulic fracturing injection treatments may be in a range from 1,000 to 15,00 pounds per square inch (PSI). In various embodiments, the pressure of the hydraulic fracturing fluid utilized in a fracturing procedure exceeds a pressure needed to fracture the formation by at least 100 PSI. 
     For a hydraulic fracturing application,  FIG.  1    depicts a configuration in which the zones covered by perforation clusters  110 A and  110 B have already been treated with injection fluid, so that a second plug, plug apparatus  114 , has been set for a third injection treatment. For example, as described above a first fluid injection operation may be performed on borehole  104 , wherein neither plug apparatus  112  nor plug apparatus  114  having been set within the borehole. During this first fluid treatment operation, perforations illustratively represented by perforation clusters  110 A within zone  108 A of the borehole may have been already provided by a perforation operation. Perforations illustratively represented by perforation clusters  110 B and/or  110 C may or may not have already been provided before the first fluid treatment operation is performed. Upon completion of the first fluid treatment operation, plug apparatus  112  is set in place in the borehole between zones  108 A and  108 B, and activated to seal off the portion of the borehole represented by zone  108 A. A second fluid treatment may then be performed on the borehole, wherein only perforation provided in perforation cluster  110 B in zone  108 B of the borehole, (and if present, perforations in perforation cluster  110 C and zone  108 C), are exposed to the fluid pressures and treatment fluid provided as part of the second fluid treatment operations. Following completion of the second fluid treatment operation, a third treatment operation may be initiated. 
     The illustration of well system  100  depicts a state of the wellbore system that may exist at the time of initiation of and throughout the performance of the third fluid treatment operation. For the third injection treatment, injection rig  130  pumps plug apparatus  114  to a position within the borehole  104  between perforation cluster  110 B and  110 C. Once plug apparatus  114  is in position, the plug is activated to lock the plug in place and provide a pressure seal against any pressurized fluid column  106  provided uphole of the plug apparatus within the borehole and proximate to the uphole side of the plug apparatus. Injection fluid is provided to form fluid column  106  may through injection rig  130  coupled to an injection system  150 . Because of the location of plug apparatus  114  below (downhole) and the position of perforation clusters  110 C located in zone  108 C, the pressurized fluid provided in fluid column  106  is in contact with and is able to apply fluid pressure to the strata  105  in the area proximate the perforation clusters  110 C. As such, a fracturing operation may be performed by well system  100  in the area of perforation clusters  110 C when configured with plug apparatus  114  in place as illustrated in  FIG.  1   . 
     Embodiments of well system  100  as illustrated in  FIG.  1    includes a monitoring/control system  140 , an injection system  150 , and a user interface  170 . Monitoring/control system  140  may operate above surface  101 , and within or proximate to injection rig  130  in various embodiments. Monitoring/control system  140  comprises, in part, one or more computer processors  141 , and one or more computer memory devices  142 , which together are configured to store and execute program instructions for monitoring and controlling the overall fluid treatment procedures that are to be or that are being performed on a wellbore, such as wellbore  104 . In various embodiments, memory  142  of the monitoring/control system  140  includes one or more programs, instructions, parameters, thresholds values, and/or other data, in the form of one or more injection applications  144 , that may be utilized by the one or more processors  144  to execute instructions designed to monitor and control the fluid treatment procedure(s) to be or that are being performed on wellbore  104 . In various embodiments, monitoring/control system  140  may comprise some combination of, or in some embodiments all of the components illustrated and described below with respect to  FIG.  9    and computer system  900 . 
     Monitoring/control system  140  is communicatively coupled to injection system  150  via a communication link, such as communication link  149 . Communication link  149  is not limited to any particular type of communication link, and may include any type or combination of devices, such as bus systems, electrical cabling, and/or wireless communication devices that allow for electronic communication to occur between the monitoring/control system  140  and one or more devices of the injection system  150 , including but not limited communications with the injection controller  151  included in the injection system  150 . In various embodiments, monitoring/control system  140  is configured to execute programs, for example a program comprising a set of parameters for dictating a particular fluid treatment process, which includes generating instructions that are communicated to the injection system  150  in order to control the operation of the injection system for providing treatment fluid(s) to the injection rig  130  based on the desired fluid treatment process to be performed on the wellbore  104 . 
     In various embodiments, based on instructions received from the monitoring/control system  140 , injection system  150  may be configured to provide a prescribed type or mixture of fluid, for example through fluid conduit  159 , to the injection rig  130  for injection into wellbore  104 . The instructions provided to injection system  150  may include instruction regarding various parameters related to the fluid(s) to be injected into the wellbore, the pressure(s) and/or pressure profiles hat are to be used to inject the fluid during the fluid treatment process, and/or instructions related to the flow rate(s) at which the fluid being used during the fluid treatment process are to be provided to the injection rig  130 . In various embodiments, monitoring/control system  140  may provide instructions to injection system  150  related to operation of specific devices, such as the operation of valves and/or related to the use of pump(s), such as the number of pumps be utilized at any given stage of a particular fluid treatment operation. In various embodiments, one or more components included within injection system  150 , such as injection controller  151 , may receive instructions from monitor/control system  140 , and based on the received instructions, may make further determinations related to the operation of the devices, such as the valves and/or pumps, which are included in injection system  150  and that are being utilized to carry out a fluid treatment operation. In various embodiments, injection system  150  may communicate information back to monitoring/control system  140 , such as a confirmation of receipt of instructions provided from the monitoring/control system, information related to the status of the mixing and/or fluid operations being performed by the injection system  150 , and/or any error or warning messages that might relate to issues, such as failed components, which might be detected by or within the injection system  150 . 
     Injection system  150  includes various components and devices configured to provide a desired mixture of fluid components to the injection rig  130  for injection into wellbore  104  as part of a fracturing or fluid stimulation procedure. As illustrated in  FIG.  1   , injection system  150  includes sources for a plurality of fluid components, such as injection fluid  153 , proppant  154 , and additives  155 . Injection fluid  153  may comprise a fluid, such as water, brine, carbon dioxide, or nitrogen, used to provide the bulk of the fluid that is injected into wellbore  104  for a fracturing process. Proppant  154  may comprise material such as sand or ceramic beads, used in combination with the injection fluid to increase the permeability of the formation. Additives  155  are not limited to any particular type of additive, and may include such materials as gelling agents, friction reducers, bactericides, permeability modifiers, foaming agent, and corrosion inhibitors. Additives may be added to the injection fluid  153  in order to alter and/or control a particular property, such as a chemical or physical property, of the injection fluid prior to the injection fluid being utilized in a fracturing or other treatment operation being performed on wellbore  104 . In various embodiments, the fluid produced/provided by the injection system is a solids-free fluid, which means it has a turbidity measurement of less than  1000  Formazin Nephelometric Units (FNU). In various embodiments, the fluid produced/provided by the injection system  150  may have a very low in drilling mud content or may be drilling mud free. 
     Embodiments of injection system  150  includes a mixing and pumping unit (unit)  152 . Unit  152  may be in fluid communication with each of the sources of injection fluid  153 , proppant  154 , and additives  155 . Unit  152  includes valving, manifolds, flow control valves, or other devices that allows the unit to controllable combine, in a desired proportion, the mixture of injection fluid, proppant, and/or additives to formulate a desired blend of material to be provided to injection rig  130  for injection into wellbore  104  as part of a fracturing or stimulation treatment being performed on wellbore  104 . Unit  152  includes one or more pumps that may draw fluid and/or materials from any the sources of injection fluid  153 , proppant  154 , and/or additives  155 . Unit  152  may include one or more pumps configured to provide the fluid pressure needed to cause the treatment fluid mixed at unit  152  to flow to the injection rig  130 , for example through fluid conduit  159 . In various embodiments, unit  152  also includes one or more pumps configured to provide the required level of fluid pressure, for example through fluid conduits coupling fluid conduit  159  to the wellbore  104  through injection rig  130 , that is needed to pressurize fluid column  106  within the wellbore to a desired pressure level as part of a fracturing or stimulation treatment operations being performed on the wellbore. In various embodiments, unit  152  may also be in fluid communication with a waste reservoir  156 , such as a waste tank or waste pit, wherein unit  152  is configured to pump fluid from wellbore  104  back through fluid conduit  159 , or an alternative fluid conduit (not shown in  FIG.  1   ), and into waste reservoir  156 , for example to relieve fluid pressure on the fluid column  106  following completion of the a fracturing or stimulation treatment procedure. 
     Embodiments of injection system  150  may or may not include an injection controller  151 . In embodiments that include the injection controller  151 , the injection controller may be a computer processing system, such as or similar to computer system  900  as illustrated and described below with respect to  FIG.  9   . Referring again to  FIG.  1   , injection controller  151  when provided may be coupled through communication link  149  with monitoring/control system  140 . In various embodiments, injection controller  151  is configured to provide control signals to unit  152  to control the operation of the valves, manifolds, and/or pumps included in unit  152  in order to control the mixing process of the fluid being prepared for injection into wellbore  104 , and/or to control the operator of the one or more pumps included in unit  152  in order to control the pressure and/or the flow rate of the treatment fluid being provided to injection rig  130  as part of a fracturing or stimulation treatment being performed on the wellbore  104 . In various embodiments, injection controller  151  receives control signals from the monitoring/control system  140  based on outputs provided by injection application  144 , which are configured to be used by injection controller  151  to operate unit  152  in order to provide the desire fluid mixture and/or the desired fluid pressures and flow rates as part of a planned fluid injection operation. In embodiments that do not include injection controller  151 , one or more processors  141  of the monitoring/control system  140  may provide control signals, for example via communication link  149 , that are configured to directly control the operations of the devices included in injection system  150 , such as unit  152 . In such embodiments, devices included in injection system  150  may be configured to provide output signals, for example output signals from one or more sensors, hat are communicated to the monitoring/control system  140 , for example via communication link  149 . The monitoring/control system  140  may be configured to receive these output signals, and provide the desired control over the injection system  150  based at least in part on these output signals received from the injection system. 
     One or more of the plug apparatuses, such as plug apparatus  112  and/or  114 , may be configured to communicate with one or more other devices within borehole  104  and/or one or more devices located above surface  101 , such as injection rig  130  and/or monitoring/control system  140 . In various embodiments, the plug apparatus  112  and/or  114  includes a fluid signal generator configured to produce fluid signals that are induced into the fluid column  106 , and thus travel from the source of the fluid signals, for example the plug apparatus  114 , through the pressurized fluid column  106  to one or more other devices. For example, injection rig  130  may include a transceiver  131  that may comprise a sensor, such as an acoustic sensor, which is configured to detect the fluid signal being transmitted through the fluid column  106 . The transceiver  131  may, based on the detected fluid signals, generate an output signal, which corresponds to the data and/or any information included in the fluid signal, and communicate the output signal to monitoring/control system  140  via communication link  133 . In various embodiments, monitoring/control system  140  includes a communication interface  143  that is configured to receive the signals sent from transceiver  131  over communication link  133 . Communication link  133  is not limited to any particular type of communication link, and may include any type of bus, electrical cabling, and/or wireless communication devices configured to transmit signal between injection rig  130  and monitoring/control system  140 . 
     In various embodiments, the fluid signals include data and/or other information generated and transmitted by the plug apparatus, such as plug apparatus  114 , and may include real-time or near real-time data related to various parameters, such as fluid pressures, fluid temperature, fluid flow rates, rates of changes in these parameters, and/or chemical properties related sensor data gathered at or near the plug apparatus while the plug apparatus is located within the wellbore and while during a fluid treatment procedure being performed on the wellbore. In various embodiments, each of plug apparatuses  112  and  114  is configured to communicate downhole sensor information, such as measured injection pressures, temperatures, flow rates, and/or chemical property information to the monitoring/control system  140 . Plug apparatuses  112  and  114  may communicate to monitoring/control system  140  via a two-stage communication link including a downhole-to-surface acoustic link through fluid column  106 , and a surface communication link  133 . In the depicted embodiment, the downhole-to-surface link comprises pressure signal transmitter components within plug apparatuses  112  and  114 , a pressurized fluid column  106  within wellbore  104 , and an acoustic receiver  131  within injection rig  130 . 
     Monitoring/control system  140  may receive the data and/or other information provided by plug apparatus  112  and/or  114 , and use the received data or other information to log and/or confirm that the fluid treatment process that is underway within the wellbore  104  is proceeding as desired and/or is operating within pre-prescribed limits for various parameters, fluid pressures, fluid temperature, fluid flow rates, rates of changes in these parameters, and/or chemical properties. In various embodiments, monitoring/control system  140  may, based on the data and/or other information received from the plug apparatus  114  and/or  112 , determine that adjustments to the fluid treatment process that is underway within wellbore  104  needs to be adjusted, and based on such a determination, may generate and communication to injection system  150  one or more instructions to alter or otherwise modify some aspect of the fluid treatments process, such as the fluid pressure and/or the rate of injection of fluid being applied to the borehole, and/or instructions to modify the mixture, and thus the chemical composition of the fluid being applied as part of the fluid treatment process. In various embodiments, monitoring/control system  140 , may not provide closed loop control of the fluid treatment process based on data received from the sensors of a downhole plug apparatus, but may for example utilize the data to update reservoir models. However, in other embodiments, monitoring/control system  140  may incorporate the data and other information received from the sensors of the downhole apparatus to perform feedback control, feedforward control, or process control functions for an ongoing fluid treatment process that is underway. In various embodiments processor  141  of the monitoring/control system  140  Amy include a control algorithm that combines the received data from the downhole sensor of the plug apparatus with previous received data into the control algorithm to calculate the parameters for the injection system  150 . 
     In various embodiments, monitoring/control system  140  may terminate a fluid treatment process that is being performed on wellbore  104  based on the data and/or other information received by the monitoring/control system from one or more of plug apparatus  114  and  112 . A termination of a fluid treatment process may be executed for example when a confirmation is made that the fluid treatment process has been successfully completed, based for example on one or more parameters such as fluid pressure, rate of changes in fluid pressures, fluid flow (acoustic noise), fluid temperatures, and/or chemical analysis of the fluids present in the proximity to the location of the plug apparatus positioned within the wellbore  104 . In various embodiments, decisions about adjustments to and or termination of the fluid treatment process may be based on any such parameter measurements, a rate of change of any measured parameter(s) a comparison of one or more parameters between different section of the borehole and/or differences between different fluid treatment processed performed on the same wellbore or different wellbores. A termination of the fluid treatment process may also be executed for example based on a determination that there is a problem or issue with the fluid treatment process that merits halting continuation of the fluid treatment process. 
     As described above, injection rig  130  may include a transceiver  131 . In various embodiments, transceiver  131  is configured to detect the fluid signals, such as variations in fluid pressure and/or fluid flow rates that were generated by plug apparatus  114  and transmitted through fluid column  106  as data. Transceiver  131  may be configured to translate these received fluid signals into another form, such as electronic signal, which are representative of the data provided in the fluid signals, and transmit the received data signals to a communication interface  143  of the monitoring/control system  140  via communication link  133 . Communication link  149  is not limited to a particular type of communication link, and may in various example be a coaxial cable, a twisted pair cable, or any other type of electrical bus configured to transmit data signals from transceiver  131  to monitoring system  140 . In various embodiments, processor  141  of monitoring system  140  is configured to receive that data signal provided by transceiver  131 , and to process these data signals using injection application  144  to generate output control signals, which may then be passed along via communication link  149  to the injection system  150 . The output control signals provided by monitoring system  140  to injection system  150  may include any signals and/or instructions that may be used by injection controller  151  to control the operation of unit  152  in order to control the mixing and the pressures and/or flow rates of the fluids being provided to injection rig  130  as part of a fluid injection or stimulation treatment operation being performed on wellbore  104 . As such, well system  100  is configured to provide closed-loop control, in real time or near real-time, with respect to fluid injection operation(s) being performed on wellbore  104 , and based in least in part of data gathered at or proximate to the fracturing zones being treated by the fluid injection operations. 
     In various embodiments, only the plug apparatus, such as plug apparatus  114  in  FIG.  1   , which is closest to the wellhead  102  and is therefore in direct contact with the fluid present in the fluid column  106  is operating to generated and provide fluid signals that are induced into the fluid column  106 . In various embodiments, one or more additional plug apparatus, such as plug apparatus  112  in  FIG.  1   , that are downhole relative to the plug apparatus closest to the wellhead  102  may be is operated to produce fluid signals. In such embodiments, these fluid signals generated by the additional downhole plug apparatus may be detected by sensors of the uphole plug, and used to generate fluid signals that are induced into the fluid column  106  based on the data and/or other information revied from the one or more downhole plug apparatus. 
     Plug apparatus, such as plug apparatus  112  and  114 , include various components that allow the plug apparatus to generate the fluid signals imposed onto the fluid column  106 . As shown in  FIG.  1   , embodiments of plug apparatus  114  may include a sensor input  120  coupled to one or more sensors  121 , and a controller  124 , an actuator  128 . Controller  124  may include one or more processors and additional computer components, such as the computer system illustrated and described with respect to  FIG.  8    and computer system  800 . The one or more sensors  121  may be configured to provide output signals related to one or more sensed parameters, such as fluid pressure, rate of changes in fluid pressures, fluid flow (acoustic noise), fluid temperatures, and/or chemical properties of the fluid or fluids present where the sensors are located within or proximate to the borehole were the plug apparatus  114  is located. The input signals provided by the sensors  121  may be received at sensor input  120  for further processing, and may then be utilized by controller  124  to generate data and other information. Controller  124  is further configured to control actuator  128  in order to impose the fluid signals onto the fluid column  106 . The fluid signal may include data corresponding directly or derived from the output signals received form the one or more sensors  121 , and/or additional information, such as check sum values, synchronization symbols, baud rate information, and any other types of information related to the data transmission being utilized by the fluid signals. As described above, the fluid signals produced by the plug apparatus  114  and imposed onto the fluid column  106  may be received at transceiver  131 , and communicated to the monitoring/control system  140 , wherein the monitoring/control system may then record, analyze and/or act upon the received data and other information. 
     In various embodiments, communication of data and/or other information may also originate from the monitoring/control system  140 , and be transmitted, for example using transceiver  131 , into fluid signals that are transmitted through fluid column  106  to plug apparatus  114 . Plug apparatus  114  may include an acoustic receiver  122  configured to detect the fluid pulse signals transmitted downhole, and to generate input signals to the controller  124  based on the detected fluid pulse signals. In various embodiments, at last some portion of the acoustic receiver and/or the transmission path from acoustic receiver  122  to monitoring/control system  140  includes fiber optics and/or fiber optic cabling. Data and information transmitted to the plug apparatus  114  from the monitoring/control system  140  may include instructions as to what types of data the plug apparatus is to gather and transmit back to the monitoring/control system, when to make such transmissions, and/or other information related to the formatting of the data and/or other information to be transmitted by the plug apparatus. In various embodiments, acoustic receiver  122  is also configured to detect the fluid signals generated by the actuator  128  of the plug apparatus  114 , and to provide a feedback signal to controller  124  based on the detected fluid pulse signals. These feedback signals may act as a check and/or confirmation that the actuator  128  is functioning properly to impose of the fluid column  106  the desired configuration of fluid pulses. 
     Embodiments of well system  100  may include a user interface device, as illustratively represented in  FIG.  1    by user interface  170 . User interface  170  may include a personal computer, a lap-top computer, or some other type of user interface device, such as a smart phone. In various embodiments, user interface  170  may include a computer system including a combination or all of the subcomponents as illustrated and described below with respect to  FIG.  9    and computer system  900 . In various embodiments, user interface  170  includes a display device, such as a monitor, which is configured to provide visual display of data and other information related to well system  100  and/or to a fluid treatment process being performed on or modeled for wellbore  104 . Computer system may include one or more input devices, such as a keyboard, computer mouse, and/or a touch screen that allow a user, such as a technician or engineer, to provide inputs to user interface  170 , which may include requests for information regarding the status of well system  100  and/or inputs that may be used to direct the fluid treatment procedures being or to be performed on wellbore  104 . Connections between user interface  170  and other devices included in in well system  100  may be provided by wired and/or wireless communication connection(s), as illustratively represented by lightning bolt  171 . Connections between user interface  170  and other devices not included in in well system  100  (not shown in  FIG.  1   ), such as databases, servers, and/or other computer devices, may be provided by wired and/or wireless communication connection(s), as illustratively represented by lightning bolt  172 . Various examples and additional details related to the features and functions that may be provided by embodiments of the plug apparatus are further illustrated and described with respect to  FIGS.  2 ,  3 ,  4 A- 4 B,  5 A- 5 D,  6 A- 6 D,  7 , and  8   .  FIG.  9    illustrates a computer system  900  that may be included, in some form, in one or more devices located above surface  101 , such as injection rig  130 , monitoring/control system  140 , and/or injection system  150 . 
       FIG.  1 A  is a cross-sectional diagram illustrating a wellbore system  1000  including plug apparatus  1010  coupled to a coiled tubing  1025 , according to various embodiments. As illustrated in  FIG.  1 A , plug apparatus  1010  is positioned within a casing  1001  of a wellbore at a location proximate one or more perforations  1003  extending from within the casing to areas outside the case, including one or more fractures  1004  that may be formed in the formation material  1005  surrounding the casing. In various embodiments, plug apparatus  1010  may be an example of plug apparatus  112  and/or plug apparatus  114  as illustrated and described above with respect to  FIG.  1   . 
     Referring again to  FIG.  1 A , plug apparatus  1010  includes a top coupling  1011  that mechanically couples the plug apparatus to a length of coiled tubing  1025 . Coiled tubing may extend from top coupling  1011  to a surface of the wellbore and beyond, wherein coiled tubing  1025  is configured to suspend and support the weight of the plug apparatus  1010  and any of the coiled tubing extending into the casing  1001 , so that the plug apparatus may be lowered into and positioned at a location downhole within the casing. As shown in  FIG.  1 A , plug apparatus is positioned proximate to the one or more perforations  1003  provided in casing  1001 . Plug apparatus  1010  further includes an upper packer  1012  mechanically coupled to the top coupling  1011  and positioned uphole from perforations  1003 , and a lower packer  1016  mechanically coupled through a manifold  1014  to the upper packer  1012 , the lower packer positioned downhole from the casing perforations. Upper packer  1012  includes an upper zonal seal  1013  that, when activated as shown in  FIG.  1 A , extends to contact an inner surface  1002  of the casing  1001 , forming a fluid seal with the inner surface  1002 . Lower packer  1016  includes a lower zonal seal  1017  that, when activated as shown in  FIG.  1 A , extends to contact an inner surface  1002  of the casing  1001 , forming a fluid seal with the inner surface  1002 . 
     When activated as illustrated in  FIG.  1 A , upper zonal seal  1013  and lower zonal seal  1017  provide an isolation zone  1018  that includes a portion of the wellbore within casing  1001  that is sealed off from being in fluid communication with other portion of the wellbore, both above the upper zonal seal and below the lower zonal seal. In various embodiments, the isolation zone  1018  includes a portion of the wellbore that includes casing perforations  1003 , and thus fractures  1004 , being in fluid communication with the isolation zone. Manifold  1014  is also included within isolation zone  1018 , wherein manifold  1014  includes one or more openings  1015 , which are configured to provide fluid communication between inner cavity  1028  of the manifold and the isolation zone  1018 . Coiled tubing  1025  includes a fluid passageway extending throughout the length of the coiled tubing, the fluid passageway configured to allow a fluid, such as a fracturing fluid, to the plug assembly and isolation zone,  1018 . The fluid may be provided from an uphole location, such as from a location above the surface where the borehole penetrates, to the top coupling  1011 , at various pressures required to perform fluid treatment operations, such as a fracturing operations, on the formation material  1005  outside casing  1001 . The flow of fluid provided to the plug apparatus through coiled tubing  1025  is illustratively represented in  FIG.  1 A  by arrow  1026 . Both the top coupling  1011  and the upper packer assembly  1012  include fluid passageways, respectively, that are in fluid communication with the fluid passageway extending through the coiled tubing  1025 , and the inner cavity  1028  of manifold  1014 , as illustratively represented by arrow  1027 . As such, a fluid provided to the plug apparatus  1010  via coiled tubing  1025  may flow through the top coupling  1011 , through upper packer assembly  1012 , and into inner cavity  1028  of the manifold  1014 . As described above, manifold  1014  includes one or more opening  1015 , which are configured to allow fluid received at the inner cavity  1028  of the manifold to flow out of the manifold, as illustratively represented in  FIG.  1 A  by arrows  1029 , to provide a fluid flow and/or to exert a fluid pressure within the isolation zone  1018 . Fluid flows and/or fluid pressures provided to isolation zone  1018  may further be provided to and/or exerted on formation  1005  in the areas of the casing perforations  1003 , in various embodiments generating fractures  1004  in the formation material, and/or provide some other type of fluid treatment to the formation material that is proximate to casing perforations  1003 . 
     In addition, embodiments of system  1000  include lower packer  1016  including a fluid passageway the provides fluid communication between the inner cavity  1028  of manifold  1014  and a telemetry unit  1020  that in various embodiments is coupled to the downhole side of the lower packer. In various embodiments, telemetry unit  1020  includes a guide nose  1022 , which may be made of a material such as steel, and be shaped in a way, such as having a rounded shape, which is configured to protect telemetry unit  1020 , and to aid in guiding the plug apparatus  1010  along a path through the casing  1001  when the packer assembly is being lowered or raised within the casing. The fluid passageway may be configured to provide a flow of fluid from the inner cavity  1028 , through the lower packer  1016 , and to the telemetry unit  1020 , as illustratively represented by arrow  1030  in  FIG.  1 A . 
     Telemetry unit  1020  includes a fluid signal generator  1021 . Fluid signal generator  1021  may be any embodiment of the fluid signal generators described throughout this disclosure, or any equivalents and/or variations thereof. In various embodiments, fluid signal generator  1021  is configured to be operated to controllable generate fluid signal pulses within the fluid column coupling the telemetry unit  1020  to the fluid column within coiled tubing  1025  through the fluid passageways extending through the plug apparatus as described above. The fluid pulse signals may be generated for example by controllably operating the fluid signal generator to at times block, and at other times allow, a flow of fluid provided to the fluid signal generator from the plug apparatus  1010  to flow out of the telemetry unit through exit port  1031 , as represented by arrow  1032 . In various embodiments, the fluid pulse signals represent data, such as data related to downhole parameters such a fluid flow rates, fluid pressure(s), fluid temperature(s) and/or information related the chemical properties determined for the fluids present in the wellbore, including fluids present within isolation zone  1018 , as part of the fluid treatment process. The type of fluid signal generator  1021  that may be included within telemetry unit  1020  is not limited to any particular type of fluid signal generator, and may include any of the embodiments of fluid signal generators described throughout this disclosure, and/or any equivalents thereof. In operation, fluid signal generator  1021  may operate to generate fluid signal pulses that represent data and/or other types of information, wherein the fluid signal pulses are transmitted from the fluid signal generator to another device, such as an acoustic receiver, through the fluid present in the plug apparatus  1010  and extending through at least a portion of the coiled tubing  1025  coupled to the packer assembly, to a device, such as an acoustic receiver (not shown in  FIG.  1 A ), whcih can detect the fluid signal pulses. 
       FIG.  1 B  is a cross-sectional diagram illustrating a wellbore system  1050  including plug apparatus  1065 , according to various embodiments. As illustrated in  FIG.  1 B , plug apparatus  1065  is positioned within a casing  1051  at a location that is downhole of one or more casing perforations  1058  and uphole of one or more casing perforations  1054 . Casing perforation  1054  may be included in a fracture zone  1053 , and may include one or more fractures  1056  extending into formation material  1055  in the areas outside the casing  1051  and proximate to casing perforations  1054 . A second fracturing zone  1057  may include one or more fractures  1059  extending into formation material  1055  from casing perforations  1058 . In various embodiments, plug apparatus  1065  may be an example of plug apparatus  112  and/or plug apparatus  114 , as illustrated and described above with respect to  FIG.  1   . 
     Referring again to  FIG.  1 B , plug apparatus  1065  is illustrated in a seated position proximate to and uphole from seat  1062 . Seat  1062  may be located at a position within casing  1051  between fracturing zones  1053  and  1057 , and is attached, for example by being welded to the casing  1051 , so that the seat is not moveable relative to its location along a longitudinal axis of the casing. Seat  1062  includes a fluid passageway  1076  that is configured to provide fluid communication between space  1070 , which is uphole relative to the seat, and space  1071 , which is downhole of the seat, prior to having plug apparatus  1065  being provided downhole and brought into sealing contact with the seat. In various embodiments, with seat  1062  in position within casing  1051 , and in some embodiments having completed a fluid treatment process performed on space  1071  and fractures  1056 , the plug apparatus  1065  is pumped or dropped downhole in an orientation so that a sealing surface  1067  of the plug apparatus is orientated downhole relative to a front face  1069  of the plug apparatus. A cross-sectional dimension, as illustratively represented in  FIG.  1 B  by arrow  1066 , and a general shape of the plug apparatus  1065  in cross-section is configured so that the orientation of the plug apparatus with the inner lining  1052  of casing  1051  will be maintained as shown in  FIG.  1 B  during the time the plug apparatus is being pumped or dropped downhole, including when the plug apparatus reaches the location within casing  1051  of seat  1062 . In various embodiments, as the plug apparatus  1065  is being pumped or dropped downhole, fluid passageway  1076  extending through the seat  1062  allows fluid now positioned between the seat and the plug apparatus to be expelled through the fluid passageway  1076  into space  1071 , thus allowing plug apparatus to move toward seat  1062  without the need to overcome fluid pressure that might otherwise build up between the plug apparatus and the seat. 
     Once plug apparatus  1065  has reached to location of the seat  1062 , the sealing surface  1067  of the plug apparatus may be brought into physical contact with a sealing surface  1063  of the seat, and thus forming a fluid tight seal between the plug apparatus and the seat, providing a fluid seal between space  1070  and space  1071 . Additional fluid pressure applied within space  1070 , for example as part of a fluid treatment process applying fluid for example from the surface of the wellbore, will also be exerted at the front face  1069  of the plug apparatus, further aiding in providing a fluid seal between the plug apparatus and the seat via sealing surface  1063  of the seat and sealing surface  1067  of the plug apparatus. Once plug apparatus  1065  is in place as shown in  FIG.  1 B , fluid pressure may be provided from uphole (to the left of break line  1060  in  FIG.  1 B ), in order to perform a fluid treatment process, such as a fracturing process, on the fractures  1059 , while isolating the previously treated fractures  1056  from any treatment process(es) being applied to fractures  1059 . 
     Embodiments of plug apparatus  1065  also include a telemetry unit  1074 . Telemetry unit  1074  is in fluid communication with space  1070  through inlet passageway  1073 , which extends from the telemetry unit to the front face  1069  of the plug apparatus. Telemetry unit  1074  is also in fluid communication with space  1071  through outlet passageway  1075 , which extends from the telemetry unit to and is aligned with fluid passageway  1076 , which extends through seat  1062 . 
     Telemetry unit  1074  further includes a fluid signal generator  1078 . Fluid signal generator  1078  may be any embodiment of the fluid signal generators described throughout this disclosure, or any equivalents and/or variations thereof. In various embodiments, fluid signal generator  1078  is configured to be operated to controllably generate fluid signal pulses within the fluid column extending into space  1070 , and in various embodiments into a fluid column extending uphole from break line  1060  to another device, such as an acoustic receiver, located uphole of plug apparatus  1065 . The fluid signal pulses may be generated for example by controllably operating the fluid signal generator to at times block, and at other times to allow, a flow of fluid provided to the fluid signal generator from space  1070  through inlet passageway  1073  to flow out through outlet passageway  1075  and fluid passageway  1076  into space  1071 . In various embodiments, the fluid pulse signals represent data, such as data related to downhole parameters such a fluid flow rates, fluid pressure(s), fluid temperature(s) and/or information related the chemical properties determined for the fluids present in the wellbore, including fluids present within space  1070  and/or space  1071 , as part of a fluid treatment process. The type of fluid signal generator  1078  that may be included within telemetry unit  1074  is not limited to any particular type of fluid signal generator, and may include any of the embodiments of fluid signal generators described throughout this disclosure, and/or any equivalents thereof. In operation, fluid signal generator  1078  may operate to generate fluid signal pulses that represent data and/or other types of information that are transmitted from the fluid signal generator to another device, such as an acoustic receiver, through the fluid present in space  1070  and beyond break line  1060 . In various embodiments, plug apparatus  1065  includes a screen  1077  covering the inlet opening to filter out particles of a particular size and larger, while still allowing the fluid pulses being generated by the fluid signal generator  1078  to be transmitted to the fluid within and uphole beyond space  1070 . 
       FIG.  1 C  is a cross-sectional diagram illustrating a wellbore system  1080  including a plug apparatus  1089 , according to various embodiments. As illustrated in  FIG.  1 C , plug apparatus  1089  is positioned within a casing  1081  at a location that is downhole of one or more casing perforations  1058  and uphole of one or more casing perforations  1054 . In arrangements that are the same as or similar to system  1050  of  FIG.  1 B , system  1080  as illustrated in  FIG.  1 C  includes one or more casing perforations  1054  included in fracture zone  1053 , and one or more fractures  1056  extending into formation material  1055  in the areas outside the casing  1081  and proximate to casing perforations  1054 , along with a second fracturing zone  1057  including one or more fractures  1059  extending into formation material  1055  in areas outside casing  1081  and proximate to casing perforations  1058 . In various embodiments, plug apparatus  1089  may be an example of plug apparatus  112  and/or plug apparatus  114  as illustrated and described above with respect to  FIG.  1   . 
     Plug apparatus may comprise a seat  1083  coupled to an extension  1084 , wherein the extension may encircle a perimeter of the seat, and wherein the extension  1084  extends, for example as a hollow cylindrical shape, in a direction along a longitudinal axis of the casing  1081  and in a direction away from seat  1083  toward the uphole direction of the well system. Extension  1084  may terminate in a tapered surface  1085  that has a slope directed inward in the direction toward a longitudinal centerline of the plug apparatus. Plug apparatus  1089  may be initially arranged in an undeployed position within casing  1081 . In the initial and undeployed position, drop device  1086  is not present and is not in contact with the plug apparatus. In the initial and undeployed position, extension  1084  may be positioned more toward the uphole direction (to the left in  FIG.  1 C ), so that the outer surfaces of the extension  1084  are proximate to and cover over perforations  1058  and inlet port  1091 . In some embodiments, while in this undeployed position, a fluid treatment process, such as a fracturing process, may be performed on fracture zone  1053 , wherein fluid and/or fluid pressure applied to space  1070  may pass through fluid passageway  1088  of seat  1083 , and be applied to fracture zone  1053  via space  1071 . 
     Plug apparatus  1085  as shown in  FIG.  1 C  is in a deployed position, wherein drop device  1086 , which may be a spherical shaped device or a dart, has been pumped down or dropped into the well system  1080 , for example using fluid pressure provided uphole of space  1070 , so that drop device  1086  moves toward and engages with the seat  1083  of the plug apparatus. In various embodiments, drop device  1086  reaches the tapered surfaces  1085  of the plug apparatus, wherein the tapered surfaces aid in guiding the drop device toward and into contact with the sealing surface  1087  of the seat  1083 . Fluid passageway  1088 , which extends through the seat  1083 , may allow any fluid pressure developing between the drop device  1086  and the seat  1083  as the drop device moves toward the sealing surface  1087  to be relieved by a fluid flow through fluid passageway  1088  and into space  1071 , thus allowing the drop device to engage with and form a fluid seal with the seat. Once drop device  1086  is seated on the seat  1083 , further fluid pressure within space  1070  will press against the drop device with a force adequate to move the plug apparatus from the undeployed position described above to the deployed position as shown in  FIG.  1 C . The casing  1081  may include one or more steps  1082  that act as stops, and thereby limit the movement of the plug apparatus in the downhole direction so that the plug apparatus no longer covers the perforations  1058  in the second fracture zone, but also has not moved far enough to cover the perforations  1054  in the first fracture zone  1053 . While in the deployed position as illustrated in  FIG.  1 C , plug apparatus  1089  forms a fluid and pressure seal between space  1070  and space  1071 . As such, the fractures  1056  of the first fracture zone  1053  are isolated from fluid pressure and any fluid treatment processes that may be applied to fractures  1059  in the second fracture zone  1057  by fluid present in space  1070 . 
     In addition, once plug apparatus  1089  is in the deployed position as illustrated in  FIG.  1 C , inlet port  1091  is open to and in fluid communication with space  1070 . Inlet port  1091  is in fluid communication with fluid passageway  1092 , whcih extends from the inlet port to telemetry unit  1093 . Telemetry unit  1093  is also in fluid communication with outlet passageway  1094 , which extends from the telemetry unit to space  1071 . Telemetry unit  1093  further includes a fluid signal generator  1095 . Fluid signal generator  1095  may be any embodiment of the fluid signal generators described throughout this disclosure, or any equivalents and/or variations thereof. In various embodiments, fluid signal generator  1095  is configured to be operated to controllably generate fluid signal pulses within the fluid column extending through fluid passageway  1092  and inlet port  1091 , and into space  1070 , and in various embodiments into a fluid column extending uphole from break line  1060  to another device, such as an acoustic receiver, located uphole of plug apparatus  1089 . The fluid signal pulses may be generated for example by controllably operating the fluid signal generator to at times block, and at other times to allow, a flow of fluid provided to the fluid signal generator from space  1070  through fluid passageway  1092  and to flow out through outlet passageway  1094  into space  1071 . In various embodiments, the fluid pulse signals represent data, such as data related to downhole parameters such a fluid flow rates, fluid pressure(s), fluid temperature(s) and/or information related the chemical properties determined for the fluids present in the wellbore, including fluids present within space  1070  and/or space  1071 , as part of a fluid treatment process. 
     The type of fluid signal generator  1098  that may be included within telemetry unit  1093  is not limited to any particular type of fluid signal generator, and may include any of the embodiments of fluid signal generators described throughout this disclosure, and/or any equivalents thereof. In operation, fluid signal generator  1098  may operate to generate fluid signal pulses that represent data and/or other types of information that are transmitted from the fluid signal generator to another device, such as an acoustic receiver, through the fluid present in space  1070  and beyond break line  1060 . In various embodiments, plug apparatus  1089  may include a screen or other device (not specifically shown in  FIG.  1 C ) covering the inlet port  1091  to filter out particles of a particular size and larger, while still allowing the fluid pulses being generated by the fluid signal generator  1098  to be transmitted to the fluid within and uphole beyond space  1070 . 
       FIG.  2    is a cross-sectional diagram illustrating a wellbore system  200  including a plug apparatus (plug)  220  comprising a fluid signal generator assembly  230  deployed within a wellbore, in accordance with various embodiments. As illustrated in  FIG.  2   , plug  220  is positioned within a borehole casing  201  that is located downhole and within a borehole formed in formation material  205 . Plug  220  is positioned within casing  201  between first fracturing zone  203  and second fracturing zone  213 . The second fracturing zone  213  is positioned closest to the uphole inlet  206  of the borehole, which extends to the borehole surface or wellhead of the borehole. The first fracturing zone  203  includes perforations  202  that extend through borehole casing  201 , and provide fluid communication between space  207  and fractures  204  that extend into formation material  205 . The first fracturing zone  203  is positioned closest to the downhole outlet  216 , which in various embodiments extends toward the bottom face or downhole termination of the borehole. The second fracturing zone  213  includes perforations  212  that extend through borehole casing  201 , and provide fluid communication between space  217  and fractures  214  that extend into formation material  205 . 
     Plug  220  is configured to provide a sealing separation between space  207  included within the casing  201 , which is located uphole from the plug  220 , and space  217  included within casing  201 , which is located downhole from plug  220 . Plug  220  comprises a housing  221  that occupies a portion of the space within casing  201  in cross-section, and a sealing member  222  that is proximate to, and in some embodiments encircles the housing  221 . Sealing member  222  is configured to seal the outside surface(s) of the housing  221  to the inner surface(s) of the casing  201  so that any fluids present in space  207  are sealed off from space  217 , and are therefore prevented from passing around the outside surfaces of the plug  220  once plug  220  is positioned at the desired location within the casing  201  and sealing member  222  is activated to be in a sealing configuration. As further described below, embodiments of plug  220  include the above-mentioned fluid signal generator assembly (assembly)  230  that is configured to controllably allow fluid communication between space  207  and space  217  through one or more fluid passageways located with the housing  221  of plug  220 , and thereby produce one or more fluid pulses that may be used to communicate data as fluid signals. Although sealing member is illustrated in  FIG.  2    as an inflatable seal, in alternative embodiments, sealing member may preventing fluid from passing around the plug apparatus using cement to seal the plug to the tool body, or other devices such as a compression-set packer preventing flow, a swellable packer preventing flow, or a chemically reacting packer preventing flow. 
     In various embodiments, assembly  230  comprises a controller  232  that is electrically and/or mechanically coupled to additional devices that allow controller  232  to controllably allow or block a flow of fluid, such as a fracturing fluid, between space  207  and space  217 . In various embodiments, the devices included in assembly  230  and configured to be controlled by controller  232  to generate fluid pulses may include some combination of a stopper  233 , a connector  234 , an actuator block  235 , an actuator  236 , and/or a biasing member  237 . As shown in  FIG.  2   , stopper  233  is mechanically coupled to connector  234  at a first end of the connector, wherein a second end of connector  234  is mechanically coupled to actuator block  235 . Actuator block  235  is configured in some embodiments to be movable back and forth in a direction that is parallel to a longitudinal axis of the plug  220  and/or the casing  201 , as indicated by arrow  238 . Movements of the actuator block  235  are transferred to the stopper  233  through connector  234 . 
     In various embodiments, when actuator block  235  is extended to the left in  FIG.  2   , stopper  233  is configured to also move to the left to a position where the stopper makes contact with a sealing portion of housing  221 , which may comprise a housing seat  225 . Housing seat  225  may be formed from a material having a shaped surface configured to provide a fluid seal when brought into physical contact with the stopper  233 . When stopper  233  is extended in the left-hand direction so that the stopper is brought into contact with housing seat  225  with a pre-determined level of force, the housing opening  223 , which is in fluid communication with space  207 , is sealed off at the end of the housing opening  223  proximate to the housing seat  225 , and any fluid communication between space  207  and space  217  through the plug  220  is substantially or completely blocked. When actuator block  235  is extended to the right in  FIG.  2   , stopper  233  is configured to move to the right, and away from housing seat  225 . When stopper  233  is extended in the right-hand direction, the end of housing opening  223  closest to housing seat  225  provides an opening that provides fluid communication between space  207  and space  217 . Due to the pressure of the fluid present in space  207 , for example fluid pressure provided by one or more uphole devices as part of a fracturing operation, a flow of some portion of the fluid present in space  207  may flow through housing opening  223 , past stopper  233 , and through one or more passages internal to the housing  221  of plug  220  (for example indicted by dashed arrow  224 ), and into space  217 . A mechanical filter  209 , such as a sand screen, may be placed in the flow path to the housing opening  223  so that the injected proppant would be restricted from entering valve assembly. 
     In various embodiments, the flow of fluid provided through housing  221  when stopper  233  is moved away from housing seat  225  generates a level of fluid flow and/or a change in fluid pressure in the fluid present in space  207  that can be detected and interpreted, for example by a monitoring system located on the surface, as a first data state, while the lack of fluid flow provided through housing  221  when stopper  233  is moved to be in contact with housing seat  225  to form a fluid seal between space  207  and space  217  can be detected and interpreted, (again for example by the monitoring system located on the surface), as a second data state. Thus, by controllably moving stopper  233  into contact with and away from housing seat  225 , and thus respectively stopping and allowing a flow of fluid between space  207  and space  217  through plug  220 , a series of different data states can be generated in a column of fluid within space  207  and casing  201  as a result of the changes in the levels of fluid flows and/or pressure levels resulting from the control over the position of stopper  233 , thereby generating data that is communicated to the surface through the varying levels of fluid pressures and/or flows generated by the fluid signal generator  230  under the control of controller  232 . 
     In various embodiments, control of the movements of actuator block  235 , and thus the movements of stopper  233  through connector  234 , may be provided by an electro-mechanical arrangement, such as a solenoid type arrangements or such as a ferroelectric actuated arrangement or an electric motor and ball screw arrangement, wherein actuator  236  may be an electrical coil or inductor, and configured to be controlled by controller  232  to generate electromagnetic field(s) that controllably move actuator block  235  back and forth, as indicated by arrow  238 . In various embodiments, an urging member  237 , such as a spring, may be included in plug  220  and configured to urge actuator block  235  in a left-hand direction as shown in  FIG.  2   , and thus urge stopper  233  in a direction toward housing seat  225 . In various embodiments, urging member  237  may apply an adequate force against actuator block  235 , which is thereby applied to stopper  233  through connector  234 , such that stopper  233  forms a fluid seal against housing seat  225  with adequate force to prevent the flow of fluids from space  207  to space  217  through housing opening  223  without the need for additional forces to be applied to actuator block  235  by the actuator  236 . In various alternative embodiments, urging member  237  is configured to supplement the force applied to actuator block  235  by actuator  236 , and thus to stopper  233 , in order to allow stopper  233  to contact housing seat  225  with a force adequate to prevent the flow of fluids from space  207  to space  217  through housing opening  223 . 
     In various embodiments, actuator  236  is configured to apply a force, for example an electromagnetic force, to actuator block  235  that is adequate to cause actuator block  235  to move in a right-hand direction as illustrated in  FIG.  2   , and thus allow stopper  233  to move away from housing seat  225 , thereby allowing fluid communication and/or a fluid flow between space  207  and  217 . In various embodiments the force applied by actuator  236  to actuator block  235  to move actuator block in a right-hand direction in  FIG.  2    is a force that is adequate to overcome the force being applied to actuator block  235  by urging member  237  when an urging member is provided as part of plug  220 . In various embodiments, actuator block  235  may be formed of material that is attracted by a magnetic field, such as a ferrous compound, and/or may itself be magnetic, such as a material formed as a permanent magnet. By operating controller  232  to control actuator  236  using variations in electromagnetic field(s), plug  220  may controllably manipulate the position of actuator block  235 , and thus the position of stopper  233  relative to housing seat  225 , and thereby controllably generated fluid pulses in a fluid that is present in space  207 . These fluid pulses can represent data that is then communicated through the fluid present in space  207  and extending through the borehole, for example to a wellhead of the borehole, to a monitoring device, such as a monitor device at the surface  101 . In various embodiments, actuator  236  may include one or more built-in position sensors that are configured to sense a position of actuator block  235 , and to provide feedback signal(s) to controller  232  indicative of the relative position of actuator block  235  within the actuator. In various embodiments, controller  232  is configured to utilize the information provided by the built-in position sensors to determine the position of stopper  233  and/or to confirm the proper operation of the movements of the actuator block  235  and/or the operation of assembly  230  in general. 
     In various embodiments, instead of using electro-mechanical devices, controller  232  may include a pneumatic or hydraulicly operated system for actuating and controlling movements of the actuator block  235 . For example, controller  232  may be configured to operate a fluid pump and a set of valves coupled to fluid lines extending to both ends of the actuator  236  (not shown in  FIG.  2   , but for example as illustrated in  FIG.  8    as the fluid pump/valves  820  and fluid ports  821 . In embodiments including the pneumatic or hydraulically operated system, controller  232  may be configured to controllably apply fluid pressure to a first end of actuator block  235  to extend stopper  233  to contact housing seat  225 , and to apply fluid pressure to a second end of actuator block  235  opposite the first end in order to retract stopper  233  in a direction away from housing seat  225 . By controlling the movements of actuator block  235  and thus the movements of stopper  233 , controller  232  can control the opening and closing of housing opening  223 , and thus control the flow of fluid through housing opening  223  to generate the fluid signals as described above. 
     In various embodiments, a power source, such as a battery, is provided as part of assembly  230 , for example integrated into controller  232 , to provide electrical power used to operated assembly  230 , including providing electrical power to actuator  236  to produce electromagnetic fields used to move actuator block  235 , and/or to provide power to operate and control pumps and valves used for pneumatic/hydraulic control of the actuator and actuator block of assembly  230 . In various embodiments, power, such as electrical power, may be provided to assembly  230  by a set of electrical conductors or an electrical cable coupling the assembly to a power source located on the surface. In various embodiments, controller  232  may be partially powered by electrical power, for example by a battery included in assembly  230 , and also provided with a source of pressurized fluid, such as air or hydraulic fluid, from a source external to the assembly  230 , the pressurized fluid configured for operating the movements of the actuator block  235  within the plug housing  221  of the assembly  230  under the control of controller  232 . 
     In various embodiments, one or more sensors  208  may be located proximate to or incorporated into plug  220  such as the housing portion of plug  220 , and configured to sense one or more parameters associated with space  207 . For example, sensors  208  may be configured to sense fluid pressure levels, temperatures, and/or one or more other parameters, such as parameters related to chemical properties of fluid(s) present in space  207 . Sensors  208  may be communicatively coupled, for example via a wired or a wireless connection, to a sensor interface included in controller  232 . Controller  232  may be configured to receive output signals provided by the one or more sensors  208 , such as electrical output signals provided by the one or more sensors  208 , the output signals representative of measurements taken by the one or more sensors related to one or more of the parameters being sensed by the sensors  208 , such as real-time pressure and/or temperatures related to the fluid(s) present in space  207 . In various embodiments, sensors  208  may include one or more sensors configured to detect the changes in fluid pressure and/or fluid flows generated by the opening and closing of the opening  223  due to the operation of the stopper  233 , and provide a feedback signal to controller  232  based on the detection of the fluid signals detected in the fluid present in space  207 . In various embodiments, these feedback signal(s) may be utilized by controller  232  to confirm the proper operation of the assembly  230  in providing fluid signals to the fluid present in space  207 . 
     In various embodiments, one or more sensors  218  may be located proximate to or incorporated into plug  220 , and configured to sense one or more parameters associated with space  217 . For example, sensors  218  may be configured to sense fluid pressure levels, temperatures, flow rates, acoustic noises, and/or one or more other parameters, such as parameters related to chemical properties of fluid(s) present in space  217 . Sensors  218  may be communicatively coupled, for example via a wired or a wireless connection, to a sensor interface included in controller  232 . Controller  232  may be configured to receive output signals provided by the one or more sensors  218 , such as electrical output signals provided by the one or more sensors  218 , the output signals representative of one or more of the parameters being sensed by the one or more sensors  218 , such as real-time pressure and/or temperatures related to the fluid(s) present in space  217 . 
     Controller  232  may be configured to process the output signals provided by the one or more sensors of sensors  208  and/or sensors  218 , and generate data based at least in part on these output signals. Controller  232  may be further configured to controllably operate the devices, such as the actuator  236 , with or without the aid of a biasing member such as biasing member  237 , to control stopper  233  in order to generate a series of fluid pulses in the fluid present in space  207  in order to communicate, for example to the surface or another uphole device, the generated data via the series of fluid pulses produced in the column of fluid present in space  207  and extending in some embodiments to the surface of wellbore where plug  220  is installed. 
     In various embodiments, portions of the assembly  230 , such as plug housing  221 , stopper  233 , housing seat  225 , and connector  234 , are formed from a material that is inert relative to the various chemicals and/or particulates that may be present in the fluid provided to space  207 , and passing through the plug  220 . In various embodiments, one or more of these components may be formed from material comprising a metal (such as steel, magnesium, or aluminum), a polymer (such as a polymer composite, an aliphatic polyester like PGA, PEEK, or Torlon), or a ceramic (such as carbide, a metal oxide like alumina, or a porcelain). In various embodiments, the portions of the plug  220  that may come into contact with fluid(s) provided in space  207  and/or passing through the plug may be coated with a different material, such as ceramic, metal, or a polymer, which are inert to and/or are configured to protect the devices coated by the surface from the chemicals and/or particulates that may be provided in the fluid(s) provided to space  207  and/or passing through the plug. For example, face portion and/or outer surfaces of plug housing  221  that are exposed to space  207 , the inner surface of housing opening  223 , and/or any portion of the passageways within plug  220  where fluids from space  207  may pass through to space  217 , may be coated with a material configured to protect the underlying material from the fluids present in these areas. 
     In various embodiments, an internal dimension D, such as a diameter, of housing opening  223  may be configured in view of various factors, such as the pressures and/or viscosities of the fluids expected to be present in space  207 , and/or the overall diameter of the borehole where plug  220  is expected to be deployed. In various embodiment, housing opening  223  is a cylinder shaped passageway having a circular shape in cross section, and having a diameter D 1  in a range of 0.050 inches to 3 inches. Non-circular cross sections, such as annular cross sections and geometric shapes are alternative embodiments. In various embodiments, the face of stopper  233  may be angled relative to the longitudinal axis of the plug, for example having a pointed shape as shown in  FIG.  2   , which helps the actuator  236  overcome the forces of the fluid pressures that may be exerted on the face of the stopper as the actuator operates to open and close the housing opening  223  using the stopper. 
     In various embodiments, portions of the fluid signal generator  230 , such as controller  232 , actuator  236 , actuator block  235 , and biasing member  237  may be enclosed in a housing  240  configured to isolate and protect these devices from any fluid present in space  207 , and from any fluid passing through plug  220  to space  217 . In various embodiments, a seal  239  is provided to seal a portion of housing  240  to allow for connector  234  to extend out of the housing  240  to couple with stopper  233  while preventing the fluid present in the housing opening  223  and passing through plug  220  from entering the housing  240  and coming into contact with the devices located within housing  240 . In various embodiments, housing  240  may be physically coupled to plug housing  221  in order to secure the position of assembly  230  and stopper  233  relative to plug housing  221 , while still providing one or more passageways, for example as illustrated by arrow  224 , for the flow of fluid around housing  240  and through plug  220 . 
       FIG.  3    is a cross-sectional diagram illustrating a wellbore system  250  including a plug apparatus (plug)  260  comprising a fluid signal generator assembly (assembly)  261  deployed within a wellbore, in accordance with various embodiments. Plug  260  as illustrated in  FIG.  3    includes features that are the same or are similar to the features described above with respect to plug  220  and  FIG.  2   , and therefore retain the same references numbers used to label these corresponding features as illustrated in  FIG.  2   . Plug  260  may provide any and/or all of the same features, and be configured to perform any and/or all of the same function described above or otherwise attributable to plug  220  of  FIG.  2   , with the variations as further described below for plug  260  of  FIG.  3   . 
     As shown in  FIG.  3   , the assembly  261  of plug  260  includes a connector  251  that is coupled to actuator block  235  at a first end of the connector, and to stopper  253  coupled to connector  251  at a second end of the connector opposite the end coupled to the actuator block. In various embodiments of plug  260 , connector  251  has a longitudinal dimension that allows the second end of the connector to extend through opening  223  of plug  260  to a position beyond a front face  254  of the plug housing  221 , the front face  254  having a surface defining an end of the plug housing that is exposed to space  207 , and provides at least some portion of the fluid boundary of space  207 . Stopper  253  may be formed as a flat shaped material, for example having a disc shape, and having a thickness dimension the extends radially in all directions from the point where stopper  253  connects to connector  251 , so that a surface of the stopper extends beyond the cross-sectional interior dimension(s) of housing opening  223 . 
     A surface of stopper  253  may be configured to be brought into contact with housing seal  252  provided at, or proximal to, the front face  254  of housing  221 , so that stopper  253  forms a fluid seal configured to substantially or completely block off the uphole opening of housing opening  223 , and thereby seal off fluid flows between space  207  and  217  through the one or more fluid passageways extending through plug  260 , as illustrative represented by dashed arrow  224 . In various embodiments, housing seal  252  provides a sealing surface that is flush with front face  254 . In various embodiments, the housing seal  252  is recessed within the plug housing  221  so that when stopper  253  is brought into contact with housing seal, the uphole face of stopper  253  is recessed within plug housing  221  and is recessed behind, or is flush with, front face  254 . Connector  251  is dimensioned so that when actuator block  235  is extended to the left-hand direction in  FIG.  3   , stopper  253  is moved away from housing seal  252 , and a passageway for the flow of fluid present in space  207  is provided through housing opening  223  and through plug  260 , for example as illustrated by dashed arrow  224 . Controller  232  may be configured to operate in any of the ways and by means of any of the devices described above with respect to plug  220  and  FIG.  2    in order to control the position of stopper  253  to provide fluid signals in the fluid present in space  207 . 
     In various embodiments, stopper  253  is configured to be received at the front face  241  of housing  221  and to form a fluid seal between space  207  and opening  223  when the stopper is fully received at the housing seat  252 . In the embodiment illustrated in  FIG.  3   , fluid pressure present in space  207  may exert a force on the uphole face of stopper  253  that aids in forming the seal between stopper  253  and housing seat  252 . In various embodiments, an urging member  237 , such as a spring, is arranged in assembly  261  in order to help push actuator block  235  to the left in  FIG.  3   , and thus contribute to any forces exerted on the actuator block  235  by actuator  236  as needed to move stopper  253  away from housing seat  252  and open the passageways(s) through plug  260  for a flow of fluid between space  207  and space  217 . An inside dimension, such as a diameter, of housing opening  223 , may be determined based on various factors, including the pressure ranges of the fluid expected to be present in space  207  when data is to be communicated using the plug  260 , the overall dimension of the borehole casing where the plug is to be installed, the composition of the fluid present in space  207 , and for example the dimensions in cross-section of connector  251  present within the housing opening  223 . Housing seat  252 , stopper  253 , and connector  251  may be formed, respectively, from one or more of the materials described above that are inert and/or provide protection from the fluids these devices may come into contact with when located and operating within a borehole environments ads part of a fluid treatment operation. It should be evident that a range of different flow restriction valves could be used. Alternative embodiments use a ball valve, spool valves, needle valves, pinch valves, poppet valves, globe vales, et cetera. Embodiments of plug apparatus  260  may incorporate a mechanical filter (not specifically shown in  FIG.  3   , but the same or similar to filter  209 ,  FIG.  3   ), such as a sand screen, may be placed over or in the flow path to the housing opening  223  so that the injected proppant would be restricted from entering valve assembly. 
       FIG.  4 A  shows a graph  400  illustrating data generated based on changes in fluid pressure within a borehole generated by a fluid signal generator, according to various embodiments. In various embodiments, the fluid signal generator may be incorporated into plug  220  as illustrated and described above with respect to  FIG.  2   , or may be incorporated into plug  260  as illustrated and described above with respect to  FIG.  3   . Referring back to  FIG.  4 A , graph  400  includes a horizontal axis  401  representing time, and a vertical axis  402  representing fluid pressure, such as a fluid pressure of a fracturing fluid present within a casing of a borehole that is pressurized against a plug, such as plug  220  of  FIG.  2    or plug  260  of  FIG.  3   . Again referring to  FIG.  4 A , graphical line  403  represents a pressure level present within the fracturing fluid that varies over time. The variations in the pressure level may be interpreted to represent data, such as data bits “1” and “0” as imposed on graph  400  to the left of bracket  406 . 
     In various embodiments, when the pressure level represented by graphical line  403  is below a lower threshold pressure level  405  during a particular time period, that pressure level may be interpreted as a first data value, for example a data value of zero (“0”). This lower pressure level may be generated by operating the fluid signal generator of a plug to allow flow of fluid through the plug or other device where the fluid signal generator is incorporated, thus generating a lower pressure level in the fluid present against one face or side of the plug, such as fluid pressure against the uphole face of the plug. When the pressure level represented by graphical line  403  is above an upper threshold pressure level  404  during a particular time period, that pressure level may be interpreted as a second data value different from the first data value, for example a data value of one (“1”). This higher pressure level may be generated by operating the fluid signal generated to block the flow of fluid through the plug or other device where the fluid signal generator is incorporated, thus retaining a higher pressure level in the fluid present against one face or side of the plug, such as fluid pressure against the uphole face of the plug. 
     As illustrated in graph  400 , during the time between T 1  and T 2 , the pressure level represented by graphical line  403  extends above the upper threshold pressure level  404 , and thus may be interpreted to represent a first data value of “1”. During the time between T 2  and T 3 , the pressure level represented by graphical line  403  remains extended above the upper threshold pressure level  404 , and thus may be interpreted to represent a first data value of “1”. During the time between T 3  and T 4 , the pressure level represented by graphical line  403  drops below the lower threshold pressure level  405 , and thus may be interpreted to represent a second data value of “0”. For the time period between T 4  and T 5 , the pressure level represented by graphical line  403  again extends above the upper threshold pressure level  404 , and thus may be interpreted to represent a first data value of “1”. During the time period between T 5  and T 8 , the pressure level represented by graphical line  403  extends below the lower threshold pressure level  405 , and thus may be interpreted to represent three consecutive data values of “0”. During the time between T 8  and T 9 , the pressure level represented by graphical line  403  again extends above the upper threshold pressure level  404 , and thus may be interpreted to represent a data value of “1”. 
     As a result of the variations in the pressure levels represented by graphical line  403 , data representing a series of data bits, representing data bits “1 1 0 1 0 0 0 1” may be imposed onto a fluid present in the wellbore, wherein these variation in pressure levels may be transmitted through the fluid to a monitoring device, thus allowing data communications to occur through the fluid, and for example to the surface of a wellbore under the control of a fluid signal generator, such as the fluid signal generator  230  included as part of plug  220  or fluid signal generator assembly  261  included as part of plug  260 . Without loss of generality, a pulse position encoding scheme or a pulse amplitude modulation encoding scheme could be used. The encoding scheme may include timing pulses, header pulses, address pulses, and error check pulses. 
     The period of time represented by the time interval between each of times T 1  to T 10  is not limited to a particular time interval, and in various embodiments may be a time interval between 0.01 seconds and 10 minutes, inclusive. The pressure levels represented by graphical line  403 , and the pressure values assigned to the upper threshold pressure level  404  and the lower threshold pressure level  405  are not limited to any particular pressure ranges, respectively, and may be determined by such factors as the pressure levels being applied to the fracking fluid proximate to the fluid signal generator present in the wellbore, and the levels of pressure variations needed in order to generate data signals that may be detected based on the changes in fluid pressure with a minimum level of errors. In various embodiments, a pressure level for the upper threshold pressure level  404  may be set within a range of 1000 PSI to 15,000 PSI inclusive, and a pressure level for the lower threshold pressure level  405  may be set within a range of 500 PSI to 14,500 PSI, inclusive. The pressure range level for the upper threshold will be higher than the pressure level for the lower threshold and this level may be adjusted based on the operating injection pressure. 
     In various embodiments, the digital signal is encoded by the amount of pressure change. The pressure change for the upper threshold pressure change level  404  may be set within 95% of the average pressure and a pressure change for the lower threshold pressure change level  405  may be set within 90% of the average pressure. The pressure may be averaged over different time windows. 
     By controlling the pressure level over the time periods represented by T 1  to T 10  in graph  400 , a series of pressure levels may be generated that are representative of data values that may be communicated by way of fluid pressure changes within a column of fracturing fluid to a monitoring device, (such as monitoring system  140  as illustrated and described with respect to  FIG.  1   ) and which may be located on or near a surface of the wellbore. Once received at the surface, the received data may be recorded and/or further processed to make determinations about one or more parameters associated with fluid treatment process, in various embodiments in real or near-real time. The received data in various embodiments may be utilized to determine when and if adjustments to the fluid treatment process, such as changes to the fluid being applied and or to other parameters, such as the rate and/or pressure of the fluid being applied to the borehole as part of the fluid treatment process need to be adjusted. 
       FIG.  4 B  shows a graph  420  illustrating data generated based on changes in fluid flows generated by a fluid signal generator, according to various embodiments. In various embodiments, the fluid signal generator is incorporated into plug  220  as illustrated and described above with respect to  FIG.  2   , or the fluid signal generator incorporated into plug  260  as illustrated and described with respect to  FIG.  3   . Referring back to  FIG.  4 B , graph  420  includes a horizontal axis  421  representing time, and a vertical axis  422  representing fluid flow rates, such as a fluid flow in a fracturing fluid present within a casing of a borehole that is pressurized against a fracturing plug, such as plug  220  of  FIG.  2    or plug  260  of  FIG.  3   . Again referring to  FIG.  4 B , graphical line  423  represents a fluid flow level present within the fracturing fluid that varies over time. The variations in the flow rate level may be interpreted to represent data, such as data imposed on graph  420  to the left of bracket  426 . 
     In various embodiments, when the fluid flow rate represented by graphical line  423  is below a lower threshold flow level  425  during a particular time period, that flow rate may be interpreted as a first data value, for example a data value of zero (“0”). Low or no fluid flow rates that fall below threshold flow level  425  may occur when a fluid signal generator is operated to block the flow of fluid present at the face of the plug where the fluid signal generator is incorporated from flowing through the plug. When the fluid flow rate represented by graphical line  423  is above an upper threshold flow level  424  during a particular time period, that flow rate may be interpreted as a second data value different from the first data value, for example a data value of one (“1”). This higher level of fluid flow may be generated by operating the fluid signal generated to allow a flow of fluid through the plug or other device where the fluid signal generator is incorporated, thus generating a level of fluid flow in the fluid present against one face or side of the plug, for example through one or more fluid passageways extending through the plug. 
     By way of example, during the time between T 1  and T 2 , the flow rate represented by graphical line  423  extends above the upper threshold flow rate level  424 , and thus may be interpreted to represent a first data value of “1”. During the time between T 2  and T 3 , the flow rate represented by graphical line  423  remains extended above the upper threshold flow rate level  424 , and thus may be interpreted to represent a first data value of “1”. During the time between T 3  and T 4 , the flow rate represented by graphical line  423  drops below the lower threshold flow rate level  425 , and thus may be interpreted to represent a second data value of “0”. For the time period between T 4  and T 5 , the flow rate level represented by graphical line  423  again extends above the upper threshold flow rate level  424 , and thus may be interpreted to represent a first data value of “1”. During the time period between T 5  and T 8 , the flow rate represented by graphical line  423  extends below the lower threshold flow rate level  425 , and thus may be interpreted to represent three consecutive data values of “0”. During the time between T 8  and T 9 , the flow rate represented by graphical line  423  again extends above the upper threshold flow rate level  424 , and thus may be interpreted to represent a data value of “1”. 
     As a result of the variations in the flow rates represented by graphical line  423 , data representing a series of data bits, including data bits “1 1 0 1 0 0 0 1” may be imposed onto a fluid present in the wellbore, wherein these variation in flow rate levels may be transmitted through the fluid to a monitoring device, thus allowing data communications to occur through the fluid, and for example to the surface of a wellbore under the control of a fluid signal generator, such as the fluid signal generator  230  included as part of plug  220  ( FIG.  2   ) or the fluid signal generator  261  included as part of plug  260  ( FIG.  3   ). 
     In graph  420  of  FIG.  4 B , the period of time represented by the time interval between each of times T 1  to T 10  is not limited to a particular time interval, and in various embodiments may be a time interval between 0.01 seconds and 10 minutes, inclusive. The flow rates represented by graphical line  423 , and the flow rate values assigned to the upper threshold flow rate level  424  and the lower threshold flow rate level  425  are not limited to any particular ranges of flow rates, respectively, and may be determined by such factors as the pressure levels being applied to the fracturing fluid proximate to the fluid signal generator present in the wellbore, the volume of fracturing fluid present in the system, and the levels variations in the flow rates that are needed in order to generate data signals that may be detected based on the changes in flow rates with a minimum level of errors. In various embodiments, a flow rate threshold value for the upper threshold flow rate level  424  may be set within a range of 1 barrel per minute (BPM) to 20 BPM inclusive, and a flow rate threshold value for the lower threshold flow rate level  405  may be set within a range of 0.5 BPM to 19.5 BPM, inclusive. The flow rate for the upper threshold will be higher than the flow rate for the lower threshold and this level may be adjusted based on the operating injection flow rate. 
     In various embodiments, the digital signal is encoded by the amount of flow rate change. The flow rate change for the upper threshold pressure change level  424  may be set within 95% of the average flow rate and a flow rate change for the lower threshold flow rate change level  425  may be set within 90% of the average pressure. The pressure may be averaged over different time windows. 
     By controlling the variations in the flow rate level over the time periods represented by T 1  to T 10  in graph  420 , a series of varying fluid flow rates in the fracking fluid present in a wellbore, wherein the variation in the fluid flow rates may be representative of data values that may be communicated within a column of fracking fluid to a monitoring device, (such as monitoring system  140  as illustrated and described with respect to  FIG.  1   ), and which may be located on or near a surface of the wellbore. Once received at the surface, the received data may be recorded and/or further processed to make determinations about one or more parameters associated with fluid treatment process, in various embodiments in real or near-real time. The received data in various embodiments may be utilized to determine when and/or if adjustments to the fluid treatment process, such as changes to the fluid being applied an/or to other parameters, such as the rate and/or pressure of the fluid being applied to the borehole as part of the fluid treatment process, need to be adjusted. 
       FIG.  5 A  is a cross-sectional diagram illustrating a wellbore system  500  including a plug apparatus (plug)  501  comprising a fluid signal generator assembly  502  deployed within a wellbore, in accordance with various embodiments. In various embodiments, plug  501  includes all or similar features as illustrated and described above with respect to  FIG.  2    and plug  220 , with the variations as further described below. For the sake of clarity, not every feature of plug  220  is labeled in  FIG.  5 A  with respect to plug  501 , but may be present in the various embodiments of plug  501 . As illustrated in  FIG.  5 A , plug  501  is positioned within casing  201  between first fracturing zone  203  and second fracturing zone  213 . Sealing member  222  is configured to seal the outside surface(s) of the plug apparatus  501  to the inner surface(s) of the casing  201  so that any fluids present in space  207  are sealed off from space  217 , and are therefore prevented from passing around the outside surfaces of the plug  501  once plug  501  is positioned at the desired location within the casing  201  and sealing member  222  is activated to be in the sealing configuration. 
     In various embodiments, plug  501  includes a fluid signal generator assembly (assembly)  502  that incorporates a controller  232  configured to control stopper  233 , connector  234 , actuator block  235 , and actuator  236  using the configurations as described herein, and any variations thereof, with the variations as described below. As illustrated in  FIG.  5 A , plug  501  includes a siren  510 . In various emblements, siren  510  is positioned within the housing opening  223 , and is configured to control the flow of fluid through housing opening  223  in order to generate fluid pulse signals in the fluid present in space  207 , as further described below. In various embodiments, siren  510  includes a first fixture  511 , which comprises a plate with one or more fluid passageways extending through the first fixture, and a second fixture  512 , positioned proximate to the first fixture, wherein the second fixture  512  may comprises a plate with one or more fluid passageways extending through the second fixture. One or both of the first fixture  511  and the second fixture  512  are configured to be positional relative to one another, for example rotationally positional relative to one another, so that at one or more positions at least a part of the fluid passageways of first fixture  511  align with at least a portion of one or more of the fluid passageways of the second fixture  512  in order to provide fluid passageway(s) that extend through both the first fixture  511  and the second fixture  512 . When in this positional relationship, siren  510  provides one or more fluid passageways that extend through first fixture  511  and second fixture  512 , thus providing fluid passageways for fluid to flow through housing opening  223 , through siren  510 , and toward stopper  233 , which may be actuated to an open position (away from housing seat  225 ), thus allowing a flow of fluid from space  207  through plug  501  (for example as indicated by dashed arrow  224 ) an into space  217 . 
     The first fixture  511  and the second fixture  512  are also configured to be positional relative to one another, for example rotationally positional relative to one another, so that no portions of the fluid passageways of first fixture  511  align with any portion(s) of the one or more fluid passageways of the second fixture  512 . When positioned in this non-aligned positional relationship, siren  510  is configured to substantially or completely block the flow of fluid through housing opening  223 . The relative positioning of first fixture  511  and second fixture  512  may be controlled by an actuator  513 , which may comprise an electrical motor, such as a stepper or servo motor, or a pneumatic or hydraulic actuator. Actuator  513  may be controlled by controller  232 , wherein controller  232  is configured to control a parameter of operation of actuator  513  in order to controllably regulate the flow of fluid from space  207  to space  217  through the housing opening  223  via siren  510 , and on through plug  501  via the fluid passageway(s) represented by dashed arrow  224 . In various embodiments, (and assuming stopper  233  has been moved to a position away from housing seat  225  in embodiments where stopper  233  is provided), actuator  513  may control the relative positioning of first fixture  511  and second fixture  512  to at times allow a flow of fluid through the siren, and at other times to block any flow of fluid through the siren. By controlling the allowing and blocking of fluid flows through the siren, and in turn through plug  501 , controller  232  may generate data in the form of fluid signals in the fluid present in space  207  (for example, as illustrated and described with respect to  FIGS.  4 A and  4 B ), wherein the fluid signals may be detected and interpreted by one or more other devices, such as devices located at the surface outside the borehole as described herein, and any equivalents thereof. In embodiments were stopper  233  is provided, stopper  233  may be utilized as a main “ON” and “OFF” seal, wherein when fluid signals are to be generated by the siren  510 , controller  232  activates the assembly  502  to move stopper  233  to a position away from housing seat  225 , thus providing an fluid passageway from the housing opening  223  to other passageways extending through plug  501 , and sealing housing opening  223  using stopper  233  and housing seat  225  when no fluid signal generation is to be performed. 
     In various embodiments, (and again assuming stopper  233  if provided is positioned to allow a fluid communication between the housing opening  223  and fluid passageways through plug  501 ), instead of alternatively providing fluid passageway through siren  510  as a first data state and blocking fluid flows through siren  510  as a second data state, configuration of siren  510  may utilize a first rate of alternation between allowing and blocking fluid flows as a first data state, and utilizing a second rate of alternations between allowing and blocking fluid flows as a second data state in order to generate fluid signals that represent data. For example, the relative positioning of first fixture  511  and second fixture  512  may be altered, for example via rotation of one or both of the fixtures, at a first rate of rotation to represent a first data state, and rotated at a second relative rate of rotation that is different from the first rate of rotation to represent a second data state. By controllably varying the rate of relative rotation of the fixtures comprising siren  510  at different pre-determined rates, the flow and/or the pressure of the fluid present in space  207  may be manipulated to produce fluid signals having different frequencies over different time periods that represent and may be interpreted by other devices as data. 
     Embodiments of actuator  513  may include devices, such as a motor, which change the relative positioning of first fixture  511  and second fixture  512  using rotary motion. In various embodiments, other mechanisms, such as alternatively shifting first fixture  511  and second fixtures  512  between a first position and a second position, which alternatively opens and blocks passageway through siren  510 , may be utilized to thereby control the flow of fluid through siren  510 , and in turn generate fluid signal in the fluid that may be present in space  207 . Power used by actuator  513  may be electrical power, provided for example by a battery (not illustrated in  FIG.  5 A ), and/or by an electrical conductors coupled to an electrical power source (not illustrated in  FIG.  5 A ) that is external to plug  501 . In various embodiments, pneumatic or hydraulic fluid may be provided to actuator from an device (not illustrated in  FIG.  5 A ) that is external to plug  520 , the fluid provided for example under pressure and operable to be used by the actuator  513  to perform the desired actuations of siren  510  including at least movement of one or both of first fixture  511  and second fixture  512  in order to generate the fluid pulse signals. It should be clear that actuator  513  and stopper  233  are not both required and that a single electromechanical actuator could be used. Embodiments of plug apparatus  501  may incorporate a mechanical filter (not specifically shown in  FIG.  5 A , but the same or similar to filter  209 ,  FIG.  3   ), such as a sand screen, may be placed over or in the flow path to the housing opening  223  so that the injected proppant would be restricted from entering valve assembly. 
       FIG.  5 B  shows a graph  530  illustrating data generated based on changes in a flow rate generated by a fluid signal generator, according to various embodiments. In various embodiments, the fluid signal generator is a siren incorporated into a plug installed in a wellbore for use as part of a fracking process, for example siren  510  and plug  501  as illustrated and described above with respect to  FIG.  5 A . Referring back to  FIG.  5 B , graph  530  includes a horizontal axis  531  representing time, and a vertical axis  532  representing flow rate, such as a fluid flow in a fracturing fluid present within a casing of a borehole that is pressurized against a fracturing plug, such as plug  501  of  FIG.  5 A . Again referring to  FIG.  5 B , graphical line  533  represents a flow rate level present within the fracking fluid that varies over time. The variations in the flow rate level may occur at different frequencies, wherein the different frequencies may be interpreted to represent data, such as data imposed on graph  530  to the left of bracket  536 . 
     In various embodiments, when the flow rate represented by graphical line  533  varies from approximately a first flow level  535  to approximately a second pressure level  534  at a first rate (frequency) over a given time period, the rate (frequency) of the flow level variations over that time period may be interpreted as a first data value, for example a data value of zero (“0”). When the pressure level variations represented by graphical line  533  varies from approximately a first flow rate  535  to approximately a flow level  534  at a second rate (frequency) over a given time period that is a different frequency relative to the first frequency, the rate (frequency) of the flow rate variations over that time period may be interpreted as a second data value, for example a data value of zero (“0”). 
     By way of example, during the time between T 1  and T 2 , the frequency of the variations in the flow rate level represented by graphical line  533  represents a first frequency value, and may be interpreted to represent a first data value of “1”. During the time between T 2  and T 3 , the frequency of the variations in the flow rate levels represented by graphical line  533  remains at the first frequency value, and thus may be interpreted to represent a first data value of “1”. During the time between T 3  and T 4 , the frequency of the variations in the flow rate levels represented by graphical line  533  changes at a different frequency, which is different (i.e., higher or lower frequency) compared to the frequency of the flow rate level changes that occurred between time T 1  and T 3 . The different frequency of flow rate level changes that occurs during the time T 3  and T 4  may be interpreted to represent a second data value of “0”. For the time period between T 4  and T 5 , the frequency of the changes in the flow rate levels represented by graphical line  533  again returns to a rate of the first frequency, and thus may be interpreted to represent a first data value of “1”. During the time period between T 5  and T 8 , the frequency of the flow rate levels changes represented by graphical line  533  corresponds with the second frequency, and thus the time periods between T 5  and T 8  may be interpreted to represent three consecutive data values of “0”. During the time between T 8  and T 9 , the frequency of the flow rate level changes represented by graphical line  533  again returns to a rate that corresponds with the first frequency, and thus may be interpreted to represent a data value of “1”. 
     As a result of the variations in the frequency of the flow rate levels represented by graphical line  533 , data representing a series of data bits, including data bits “1 1 0 1 0 0 0 1” may be imposed onto a fluid present in the wellbore, wherein these variation in the frequency of the flow rate level changes may be transmitted through the fluid to a monitoring device, thus allowing data communications to occur through the fluid, and for example to the surface of a wellbore under the control of a fluid signal generator, such as the siren  525  included as part of plug  520  as illustrated and described in  FIG.  5 A . 
     The period of time represented by the time interval between each of times T 1  to T 10  is not limited to a particular time interval, and in various embodiments may be a time interval between 0.01 seconds and 10 minutes, inclusive. The flow rate levels represented by graphical line  533 , and the flow rate values assigned to the upper flow rate level  534  and the lower flow rate level  535  are not limited to any particular pressure ranges, respectively, and may be determined by such factors as the pressure levels being applied to the fracking fluid proximate to the fluid signal generator present in the wellbore, and the levels of fluid flow variations needed in order to generate data signals that may be detected based on the changes in fluid flows with a minimum level of errors. 
     Further, the frequencies used to vary the flow rate levels are not limited to any particular frequencies or changes of frequencies, and may include frequencies between 5 Hertz and 500 Kilohertz, inclusive. The difference between the frequency for a variation in the flow rate level determined to represent a first data value and a frequency for a variation in the flow rate levels determined to represent a second data value is not limited to a particular difference in frequency values, and may be determined in order to minimize the amount of data errors that may occur as a result of the generation and detection of these frequency variations. In various embodiments, the different between these frequencies of pressure level variations may be between 1% and 25% of the highest frequency, inclusive. 
     It would be understood that instead of detecting variations in the frequency of the flow rate levels of the fracking fluid as illustrated in  FIG.  5 B , the monitoring system used to detect these variations in the fluid pressure levels generated by the siren could also detect differences in the frequencies of fluid pressure pulses instead of the variations in flow rates, and thereby communicate that data generated by the siren based on changes in the frequency of the variations of fluid pressure over given time periods. 
       FIGS.  5 C and  5 D  illustrate an end view of a siren  560  according to various embodiments. In various embodiments, siren  560  represents an embodiment of siren  510  as illustrated and described above with respect to wellbore system  500  and  FIG.  5 A . Referring first to  FIG.  5 C , siren  560  comprises a first plate  561  having a circular shaped outer perimeter and a thickness dimension (extending into the drawing of  FIG.  5 C ). First plate  561  includes a center opening through which an axel  565  extends. The center opening may include a seal  566  that encircles the axel  565  and provides a fluid seal between the first plate  561  and axel  565 . First plate  561  includes a plurality of openings  562  that extend through the thickness dimension of the first plate, and provide passageways for a fluid, such as a fracturing fluid, to pass through the first plate. In various embodiments, first plate  561  is configured to rotate around axel  565 , for example in a rotary direction indicated by arrow  572 . 
     A second plate  563  having a circular shaped outer dimension and a thickness dimension is positioned behind first plate  561  (i.e., positioned into the drawing in  FIG.  5 C  relative to the first plate) in a coaxial manner relative to the centers of the plates in cross-section. In some embodiments, second plate  563  may also include a center opening that encircles axel  565 . In other embodiments, axel  565  may not extend to or through the second plate, wherein second plate  563  may otherwise be secured to another structure, such as a housing of the siren. Second plate  563  includes a plurality of openings  564  that extend through the thickness dimension of the second plate, and provide passageways for a fluid, such as a fracturing fluid, to pass through the second plate. 
     When positioned as shown in  FIG.  5 C , the plurality of openings  562  in first plate  561  do not align with the plurality of opening  564  in second plate  563 , and therefore the is no open passageway for fluid to flow from the top side of the first plate, through the first and second plates, and out the bottom of the second plate. In various embodiments, a spacer or seal, such as seal  515  as illustrated in  FIG.  5 A , may be positioned between first plate  561  and second plate  563  to aid in sealing off a fluid pressure and/or a fluid flow between the first plate and the second plate other than the flow occurring when the openings  562  in the first plate and the opening  564  in the second plate are at least partially aligned. However, as the first plate  561  is rotated relative to the axial orientation of second plate  563 , the plurality of opening  562  may be brought into alignment with the plurality of opening  564  in the second plate, and thereby provide a plurality of flow paths through the aligned openings for a flow of fluid from the top of the first plate, through both the first plate and the second plate, and then out of the bottom surface of the second plate. 
     At some point in the rotation, the plurality of openings in the first plate will completely align with the plurality of openings in the second plate, as illustratively represented by  FIG.  5 D . When in this position, siren  560  would allow a maximum level of fluid flow through the siren, and may generate a maximum level of pressure drop in the pressure of the fluid present in the proximity of the top face of the first plate. As first plate  561  continues to rotate relative to second plate  563 , the alignments of openings  562  with openings  564  will initially decrease, and will eventually return to a position, for examples as shown in  FIG.  5 C , wherein there is no alignment between the openings  562  and  564 . At this point, fluid flow passing through the first plate  561  and the second plate  563  will again be substantially or completely blocked off. 
     By rotating the first plate  561  relative to the second plate  563  as described above at a first rate of rotation, a variation in the flow rate through siren  560  at a first frequency can be established. By changing that rate of the relative rotation of the first plate  561  relative to the second plate  563 , a variation in the flow rate through siren  560  at a second frequency that is different from the first frequency can be established. 
     In various embodiments, the rotary motion imparted to first plate  561  may be provided by an electrical motor, such as a stepper motor, or other devices, such as a pneumatic or a hydraulic rotary driven device. By varying the rotational rate of first plate  561  relative to second plate  563 , the rate of alignment and non-alignment of the plurality of opening in these respective plates may be controlled, and thus generate a corresponding set of pulses in pressure drop and/or fluid flow through the siren, which in turn can be detected and interpreted as data as described throughout this disclosure, and/or via any equivalents thereof. For example, by varying the rate of rotation of the first plate  561  of siren  560  between a first rate of rotation and a second rate of rotation at different time periods, two different frequencies of pressure changes and/or changes in fluid flows can be generated in a manner similar to that described above with respect to graph  530  and  FIG.  5 B . 
     The shape, positioning, and total number of openings illustrated in  FIGS.  5 C and  5 D  for first plate  561  ad second plate  563  are intended to be non-limiting examples. The shapes, relative positioning, and the total number of openings provided in the first plate  561  and the second plate  563  may be varied while still being used to facilitate the features and the functionality as described with respect to siren  560 . In various examples, the number, shape, and/or layout of opening(s) provided in first plate  561  may be different from the number, shape and/or the layout of the openings provided in second plate  563 . 
     In various embodiments, siren includes a sensor  570  configured to detect the rotation of one or both of first plate  561  and/or second plate  563 . Sensor  570  is not limited to any particular type of sensor, and may be any type of sensor, such as a Hall effect sensor, optical sensor configured to detect rotation of one or both the plates included in siren  560 . Sensor  570  may be configured to provide an output signal, such as an electrical signal, to a controller or other sensor interface through a connection, such as cable  571 , wherein the output signal is indicative of the rate or lack thereof of rotation of one or more of the plates included in siren  560 . The output signal may be used as feedback information to confirm the proper operation of the siren. 
       FIG.  6 A  is a cross-sectional diagram illustrating a wellbore system  600  including a plug apparatus (plug)  601  comprising a fluid signal generator assembly  602  deployed within a wellbore, in accordance with various embodiments. In various embodiments, plug  601  includes all or similar features as illustrated and described above with respect to  FIG.  2    and plug  220 , with the variations as further described below. For the sake of clarity, not every feature of plug  220  is labeled in  FIG.  6 A  with respect to plug  601 , but may be present in the various embodiments of plug  601 . As illustrated in  FIG.  6 A , plug  601  is positioned within casing  201  between first fracturing zone  2032  and second fracturing zone  213 . Sealing member  222  is configured to seal the outside surface(s) of the housing plug  601  to the inner surface(s) of the casing  201  so that any fluids present in space  207  are sealed off from space  217 , and are therefore prevented from passing around the outside surfaces of the plug  601  once plug  601  is positioned at the desired location within the casing  201  and sealing member  222  is activated to be in the sealing configuration 
     In various embodiments, plug  601  includes a fluid signal generator assembly (assembly)  602  that incorporates a controller  232  configured to control stopper  233 , connector  234 , actuator block  235 , and actuator  236  using the configurations as described herein, and any variations thereof. In addition, plug  601  includes a fluid vortex  610 . In various emblements, fluid vortex  610  is positioned within the housing opening  223 , and is configured to control the flow of fluid through housing opening  223  in order to generate fluid pulse signals in the fluid present in space  207 , as further described below. In various embodiments, fluid vortex  610  a fluid diverter  611  configured to shift the flow path of fluid between a first and second flow path, and thus a flow direction, through fluid vortex  610 . During the period of time when the fluid diverter  611  is shifting between a first position and a second position, and thus shifting the direction of the flow of fluid through the fluid vortex  610 , the fluid of fluid through the fluid vortex may be substantially or completely blocked off or a period of time, thus generating a pulse in the fluid pressure and/or the fluid flow rate through housing opening  223  (assuming stopper  233  is actuated to a position away from housing seat  225  to allow fluid flows out of housing opening  223  and through plug  601  to space  217 . 
     By controlling the operation of fluid diverter  611 , and thus the timing of the generation of fluid pluses, controller  232  may generate data in the form of fluid signals in the fluid present in space  207  (for example, as illustrated and described with respect to  FIGS.  4 A and  4 B ), wherein the fluid signals may be detected and interpreted by one or more other devices, such as devices located at the surface outside the borehole as described herein, and any equivalents thereof. In embodiments were stopper  233  is provided, stopper  233  may be utilized as a main “ON” and “OFF” seal, wherein when fluid signals are to be generated by the fluid vortex  610 , controller  232  activates the assembly  230  to move stopper  233  to a position away from housing seat  225 , thus providing an fluid passageway from the housing opening  223  to other passageways extending through plug  601 , and sealing housing opening  223  using stopper  233  and housing seat  225  when no fluid signal generation is to be performed. Embodiments of plug apparatus  601  may incorporate a mechanical filter (not specifically shown in  FIG.  6 A , but the same or similar to filter  209 ,  FIG.  3   ), such as a sand screen, may be placed over or in the flow path to the housing opening  223  so that the injected proppant would be restricted from entering valve assembly. 
     Embodiments of fluid diverter  611  may include devices, such as a motor, a solenoid, a ferroelectric actuator, or a pneumatic or hydraulic device configured to change the relative positioning of the fluid diverter  611 , and thus generate the fluid pulses in the fluid that may be present in space  207 . Power used by fluid diverter  611  may be electrical power, provided for example by a battery (not illustrated in  FIG.  6 A ), and/or by an electrical conductors coupled to an electrical power source (not illustrated in  FIG.  6 A ) that is external to plug  601 . 
       FIG.  6 B  shows a graph  630  illustrating data generated based on changes in a flow rate generated by a fluid signal generator, according to various embodiments. In various embodiments, the fluid signal generator is a fluid vortex incorporated into a plug installed in a wellbore for use as part of a fracking process, for example fluid vortex  610  and plug  601  as illustrated and described above with respect to  FIG.  6 A . Referring back to  FIG.  6 B , graph  530  includes a horizontal axis  631  representing time, and a vertical axis  632  representing flow rate, such as a fluid flow in a fracturing fluid present within a casing of a borehole that is pressurized against a fracturing plug, such as plug  601  of  FIG.  6 A . Again referring to  FIG.  6 B , graphical line  633  represents a flow rate level present within the fracking fluid that varies over time. The variations in the flow rate may include distinct drop in the relative level of the flow rate, wherein the timing of the distinct drops may be interpreted to represent data that is intended to be transmitted through a fluid column to one or more devices outside of the plug generating the fluid pulses represented by graphical line  633 . In various embodiments, these drops or dips in the fluid flow rates may be generated by the shifting of the flow diverter operating in conjunction with a fluid vortex device, such a fluid diverter  611  and fluid vortex  610  as illustrated and described above with respect to  FIG.  6 A . 
     Referring back to  FIG.  6 B  In various embodiments, when the flow rate represented by graphical line  633  varies over a relatively small range of flow values initially. During the time period represented by time  636 , the flow rate drops or dips an amount that is larger, for example by a pre-determined percentage, compared to the relatively small range of variations in flow rates present prior to time period  638 . The timing of this drop in flow rate may represent a fluid pulse configured to represent data being imposed onto a fluid column within a wellbore. As illustrated in graph  630 , following time period  636 , the flow rate of the fluid represented by graphical line  633  returns to a state have a relatively small range of flow values, similar to the at present in the fluid prior to time period  636 . Again, at the subsequent time period represented by time period  638 , the flow rate of the fluid as represented by graphical line  633  drops or dips by an amount that is larger, for example by a pre-determined percentage, compared to the relatively small range of variations in flow rates present just prior to time period  638 . The timing of this drop in flow rate may represent a fluid pulse configured to represent data being imposed onto a fluid column within a wellbore. As illustrated in graph  630 , following time period  638 , the flow rate of the fluid represented by graphical line  633  returns to a state have a relatively small range of flow values, similar to the at present in the fluid prior to time period  636  and just prior to time period  638 . In various embodiments, the dips in fluid flow rates may be detected as a fluid signal pulse when the fluid flow rate drops below a pre-determined flow rate, for example the flow rate indicated by dashed line  635  in graph  630 . 
     As a result of the variations in the timing and/or the frequency of the drops in fluid flow rates, for example as illustratively represented for graphical line  633  during time periods  636  and  638 , data representing a series of data bits, including data bits may be imposed onto a fluid present in the wellbore, wherein these variation in the timing and/or frequency of the dips in the flow rate level changes may be transmitted through the fluid to a monitoring device, thus allowing data communications to occur through the fluid, and for example to the surface of a wellbore under the control of a fluid signal generator, such as the siren  525  included as part of plug  520  as illustrated and described in  FIG.  5 A . 
     The period of time represented by the time interval between each of time periods  636  and  638  is not limited to a particular time interval, and in various embodiments may be a time interval between 0.01 seconds and 10 minutes, inclusive. The flow rate levels represented by graphical line  633 , and the flow rate values assigned to the pre-determined lower flow rate level  635  are not limited to any particular pressure ranges, respectively, and may be determined by such factors as the pressure levels being applied to the fracking fluid proximate to the fluid signal generator present in the wellbore, and the levels of fluid flow variations needed in order to generate data signals that may be detected based on the changes in fluid flows with a minimum level of errors. In various embodiments, a flow rate level for the pre-determined flow rate level  635  may fall within a range of 1 BPM to 20 BPM, inclusive. 
     Further, the frequencies used to vary the timing of the drops in the flow rates are not limited to any particular frequencies or changes of frequencies, and may include frequencies between 5 hertz and 500 kilohertz, inclusive. The difference between the frequency for a variation in the flow rate level determined to represent a first data value and a frequency for a variation in the flow rate levels determined to represent a second data value is not limited to a particular difference in frequency values, and may be determined in order to minimize the amount of data errors that may occur as a result of the generation and detection of these frequency variations. In various embodiments, the different between these frequencies of pressure level variations may be between 1% and 25% of the highest frequency, inclusive. 
     It would be understood that instead of detecting variations flow rate levels of the fracking fluid as illustrated in  FIG.  6 B , the monitoring system used to detect these variations in the fluid pressure levels generated by the fluid vortex could also detect differences in the variations in fluid pressure pulses instead of the variations in flow rates, and thereby communicate that data generated by the siren based on changes in the frequency of the variations of fluid pressure over given time periods. 
       FIG.  6 C  illustrates a side view of a fluid vortex  650  incorporated into a fluid signal generator according to various embodiments. In various embodiments, fluid vortex  650  is incorporated into a fracturing plug installed in a wellbore for use as part of a fracking process, for example as fluid vortex  625  and plug  620  as illustrated and described above with respect to  FIG.  6 A . As show in  FIG.  6 A , fluid vortex  650  includes a vortex body  651  coupled to be in fluid communication with a first input leg  654 , a second input leg  655 , and an exit port  653 . A diverter  656  includes a through passageway  670  that is in fluid communication with an input port  657 . Diverter  656  is configured to be positioned so that input port  657  and passageway  670  are aligned with the first input leg  654  to allow a flow of fluid entering input port  657  to flow through the diverter and enter the first input leg, while blocking off the entrance to the second input leg  655 . Diverter  656  is further configured to be positioned so that input port  657  and passageway  670  are aligned with the second input leg  655  to allow a flow of fluid entering input port  657  to flow through the passageway of the diverter and enter the second input leg, while blocking off the entrance to the first input leg  654 . 
     The vortex body  651  is configured in a circular manner such that any fluid entering into the vortex body from first input leg  654 , as indicated by arrow  659 , is directed in a generally circular flow around the vortex body, in a direction indicated by arrow  652 , before exiting the fluid vortex  650  via exit port  653 . Because of the flow path imposed on the fluid(s) entering the vortex body  651  from first input leg  654 , a certain level of back pressure is maintained on the fluid, represented by arrow  658 , which is entering the fluid vortex  650  through input port  657  and passing through passageway  670  of diverter  656 . 
     Now referring to  FIG.  6 D , diverter  656  and input port  657  have been shifted in position, in a direction illustratively represented by arrow  672 , so that passageway  670  of the diverted is aligned with the second input leg  655 , and the entrance to first input leg  654  is blocked. When configured as illustrated in  FIG.  6 D , the flow of fluid as represented by arrow  658  into input port  657  is directed into second input leg  655 , as generally indicated by arrow  673 . The flow of fluid continues through second input leg  655  and into the vortex body  651 , creating a flow of fluid within the vortex body generally indicated by arrow  674 , before exiting through exit port  653 . When in this configuration, diverter  656  also blocks off the entrance to first input leg  654 , but preventing the fluid circulating around the vortex body from exiting out through first input leg  654 . 
     During the time of transition of the diverter between the configurations illustrated in  FIG.  6 C  and  FIG.  6 D , the passageway  670  moves through a position wherein that passageway does not align with either of the inputs to first input leg  654  or second input leg  655 . During this transition time, all or most of the fluid flow through passageway  670  is blocked off, creating a pulse in the level of fluid flow passing through the fluid vortex. In addition, a similar condition occurs when the diverter is shifted back from the position shown in  FIG.  6 D  to the configuration shown in  FIG.  6 C , wherein during the time period when the passageway  670  does not align with either the inputs of the first input leg or the second input leg  655 , the flow of fluid into the fluid vortex Amy be completely or nearly completed blocked. 
     By controlling the timing and or the frequency of these shifts in the position of the diverter back and forth between the configurations shown in  FIGS.  6 C and  6 D , a series of pulses may be generated in the fluid flow entering the fluid vortex that can be interpreted as data. 
       FIG.  7    is a flow chart illustrating a method  700  for providing fluid signal generation as part of a wellbore treatment operation, according to various embodiments. One or more of the steps included in method  700  may be performed any the devices described throughout this disclosure, including by one or a combination of the devices illustrated and described above with respect to  FIG.  1    and system  100 . The fluid signal generated used to received sensor signals from one or more sensors positioned downhole and proximate or included as part of the plug apparatus and configured to generate the fluid pulses that are transmitted through the column of fluid present in the wellbore where the plug apparatus is located may be any of the plug apparatus and fluid pulse signal generator devices described throughout this disclosure, and any equivalents thereof. 
     Referring back to  FIG.  7   , in various embodiments method  700  includes establishing a pressure seal for a next treatment zone within a wellbore (block  702 ). Establishing a pressure seal for a next treatment zone may include setting a plug, such as an injection pressurization plug, at a location within the wellbore that is above a previously treated zone within the wellbore. In various embodiments, the location of the plug may be just downhole from a next set of perforation clusters that are to be treated as part of the subsequent wellbore treatment process. The installed plug includes at least one of fluid signal generator or incorporated into the plug and/or otherwise configured to control a flow of fluid provided within the next treatment zone. 
     In various embodiments, method  700  includes injecting a treatment fluid mixture into borehole (block  704 ). 
     In various embodiments, method  700  includes receiving output signals from downhole sensor(s) (block  706 ). 
     In various embodiments, method  700  includes processing signals provided by downhole sensor(s) to generate data (block  708 ). 
     In various embodiments, method  700  includes transmitting the data using fluid signals generated by a fluid signal generator assembly (block  710 ). 
     In various embodiments, method  700  includes detecting fluid signals at one or more uphole devices (block  712 ). In various embodiments the uphole device(s) includes an acoustic receiver. 
     In various embodiments, method  700  includes generating injection operation data based on detected fluid signals (block  714 ). 
     In various embodiments, method  700  includes apply injection operation data to confirm and/or to generate control modifications related to one or more parameters associated with the injection operation (block  716 ). 
     In various embodiments, method  700  includes determining if modifications to the injection process are required, and/or whether to continue the fluid injection treatment being performed on the wellbore (block  720 ). If “YES”, the method includes returning to block  704 . If “NO”, the method includes determining if the treatment process is complete. If “YES”, method  700  includes going to end. If “NO”, method  700  includes returning to block  702 . 
       FIG.  8    illustrates a block diagram of an example computer control system  800  that may be employed to practice the concepts, methods, and techniques disclosed herein, and variations thereof. In various embodiments, system  800  includes a plurality of components of the system that are in electrical communication with each other, in some embodiments using a bus  803 . System  800  may include any suitable processor  801 , along with computer memory  802 , and a controller  805 . Processor  801  may be configured to perform functions, based on programming and data stored in memory  802 , to carry out the methods, and to control apparatus related to the operation of controller  805  in order to perform generation of fluid signals when provided in a plug apparatus positioning in a borehole as described throughout this disclosure, and any equivalents thereof. 
     In various embodiments, computing system  800  may be a general-purpose computer, and includes a processor  801  (possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer system  800  includes memory  802 . The memory  802  may be system memory (e.g., one or more of cache, SRAM, DRAM, zero capacitor RAM, Twin Transistor RAM, eDRAM, EDO RAM, DDR RAM, EEPROM, NRAM, RRAM, SONOS, PRAM, etc.) or any one or more of the possible realizations of machine-readable media. The computer system  800  also includes the bus  803  (e.g., PCI, ISA, PCI-Express, HyperTransport® bus, InfiniBand® bus, NuBus, etc.) and a network interface  811  (e.g., a Fiber Channel interface, an Ethernet interface, an internet small computer system interface, SONET interface, wireless interface, etc.). Network interface  811  may be configured to provide a communication link to one or more other computer devices or systems, whcih for example be me used to download programming memory  802 , upload data stored in memory  802 , and/or perform any other types of inter-device communication with the device that includes computer system  800 . Embodiments of computer system  800  may include an internal power source  804 , such as a battery or supercapacitor, which is configured to provide electrical power to operate one or more of the components included in computer system  800 , including controller  805  and/or one or more devices coupled to controller  805 . 
     In various embodiments, controller  805  may be configured to receive instructions from processor  801 , and based on the received instructions, operate one or more devices configured as actuator  808 . For example, controller  805  may be an embodiment of controller  232  ( FIG.  2   ), a controller configured to control the operation of siren  510  or fluid vortex  610 , wherein controller  805  is configured to control the operations of the actuator  808  in order to produce fluid signals in a column of fluid as described above, and/or any equivalents thereof. In various embodiments, controller  805  includes a sensor interface  806  coupled to one or more sensors  807 . Sensors  807  may be any of sensors located downhole within a borehole, such as sensor  208 / 218  ( FIG.  2   ), which are configured to provide sensor output signals to sensor interface  806 . Sensors  807  may be hardwired to controller  805 , and/or may be linked to controller  805  via a wireless connection. Based on the received sensor output signals, controller  805  may, in conjunction with instructions received from processor  801 , control the operation of the actuator  808  in order to produce the fluid pule signals that are to be imposed on a column of fluid within a wellbore in order to transmit data to an uphole device, such as a surface device that may include an acoustic receiver. 
     In various embodiments, actuator  808  may be an electrically and/or electromechanically controlled device, controllable by electrical signal provided by controller  805 . In embodiments of a plug apparatus wherein actuator  808  is a pneumatically or hydraulically actuated device, controller  805  may include actuator fluid pump/valving  820 , which under the control of controller  805  may be used to provide control over a fluid, such as a pneumatic or hydraulic fluid, to various fluid ports  821  of the actuator  808  in order to control the operation of the actuator. For example, actuator fluid pump/valving  820  may be configured to provide fluid pressures via fluid ports  821  to different sides of an actuator block, such as actuator block  235  ( FIG.  2   ), in order to controllably shift the position of the actuator block and thereby controllably operate a stopper, such as stopper  233  ( FIG.  2   ) in order to produce a desired sequence of fluid pluses to be transmitted through a column of fluid within the wellbore and to another device, such as an uphole monitoring device such as injection rig  130 , which may be located at or otherwise above surface of the wellbore. 
     In various embodiments, computer system  800  may include acoustic receiver/sensor (receiver)  810 . Receiver  810  may be configured to sense the fluid signals generated by actuator  808 , and provide output signals, such as an electrical output signal, which may be provided to other devices such as processor  801  and/or by controller  805 . The received output signals provided by receiver  810  may be used as a feedback signal that may be used to confirm the proper operation of the actuator  808  by confirming that the actual fluid signals imposed on the fluid column and detected by the receiver  810  conform to the intended fluid signals that the processor and the controller  805  are attempting to impose of the fluid column. 
       FIG.  9    illustrates a block diagram of an example computer system  900  that may be employed to practice the concepts, methods, and techniques disclosed herein, and variations thereof. Embodiments of computer system  900  may represent a computer system located at or incorporated into one or more components of a well system, such as well system  100 , including being provided as part of injection rig  130 , monitoring/control system  140 , injection system  150 , and/or user interface computer  170  as illustrated and described above with respect to  FIG.  1   . Referring back to  FIG.  9   , computer system  900  may include a combination of, or all of the components illustrated in  FIG.  9   , including processor  901 , memory  902 , controller  905 , sensors  907 , actuators  908 , acoustic receiver  910 , and network interface  911 . 
     Processor  901  is not limited to any particular type of processor, and may comprise multiple processors as described above with respect to processor  801  ( FIG.  8   ). Memory  902  is not limited to any particular type of computer memory, and may comprise one or more different types of computer memory devices, such as any of the memory devices described above with respect to memory  802 . Referring again to  FIG.  9   , controller  905  is not limited to any particular type of controller or control devices, and may comprise any type of control devices, such as motors, pumps, controllable valves, which are configured to provide any other functions and to provide any of the features needed to operate the well system as described herein, and any equivalents thereof. Controller  905  may be coupled to receive output signals from one or more sensors  907 . Sensors  907  are not limed to any particular type of sensors, and may include any type of sensors needed to monitory the operation of the well system. For example, sensor  907  may include sensors configured to sense fluid pressure, temperatures, and/or flow rated related to fluid being utilized as part of a fluid treatment procedure to be or being performed on a wellbore. In addition, controller  905  may be coupled to one or more actuators  908 , and configured to control the operation of the one or more actuators in order to perform any of the functions associated the generation of fluid pulse signals to be transmitted uphole through a column of fluid provided to the wellbore as part of a fluid treatment procedure, such as a fracturing procedure. 
     Embodiments of computer system  900  may include acoustic receiver/sensor (receiver  910 ). Receiver  910  may be located as an uphole device, such as injection rig  130  ( FIG.  1   ), and configured to detect fluid signal present in a fluid column present in a wellbore, and to produce and output signal, such as an electrical signal, the corresponds to the detected fluid signals. The output signal provided by receiver  910  may be utilized by other devices, such as processor  901 , as a source of data transmitted via the fluid signal from a downhole device, such as a plug apparatus, and utilized to record, monitor, and/or to make adjustments to a fluid treatment process that is being performed on the wellbore being monitored by receiver  910 . 
     In various embodiments, computer system  900  includes a network interface  911  configured to allow computer system  900  to communicate with other devices, such as other devices that include additional computer systems. In various embodiments, computer system  900  include an image processor  913 . Image processor in various embodiments is configured to process data that is available within the system, including data transmitted from a downhole device such as a plug apparatus to a device at the surface of the wellbore, and to generate image data that can then be used to provide visual displays, such as graphical displays at a computer monitor, based on the processed data and/or other information available to the system. 
     In various embodiments, computer system  900  includes a plurality of components of the system that are in electrical communication with each other, in some embodiments using a bus  903 . 
     It will be understood that one or more blocks of the flowchart illustrations and/or block diagrams, and combinations of blocks in the flowchart illustrations and/or block diagrams, can be implemented by program code. The program code may be provided to a processor of a general-purpose computer, special purpose computer, or other programmable machine or apparatus. As will be appreciated, aspects of the disclosure may be embodied as a system, method or program code/instructions stored in one or more machine-readable media. Accordingly, aspects may take the form of hardware, software (including firmware, resident software, micro-code, etc.), or a combination of software and hardware aspects that may all generally be referred to herein as a “circuit,” “module” or “system.” The functionality presented as individual modules/units in the example illustrations can be organized differently in accordance with any one of platform (operating system and/or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc. 
     Computer program code for carrying out operations for aspects of the disclosure may be written in any combination of one or more programming languages, including an object oriented programming language such as the Java® programming language, C++ or the like; a dynamic programming language such as Python; a scripting language such as Perl programming language or PowerShell script language; and conventional procedural programming languages, such as the “C” programming language or similar programming languages. The program code may execute entirely on a stand-alone machine, may execute in a distributed manner across multiple machines, and may execute on one machine while providing results and or accepting input on another machine. While depicted as a computing system or as a general purpose computer, some embodiments can be any type of device or apparatus to perform operations described herein. 
     While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. In general, techniques for implementing formation testing as described herein may be performed with facilities consistent with any system or systems. Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. 
     Use of the phrase “at least one of” preceding a list with the conjunction “and” should not be treated as an exclusive list and should not be construed as a list of categories with one item from each category, unless specifically stated otherwise. 
     Example embodiments are provided as follows: 
     Embodiment 1. An apparatus comprising: a plug apparatus positionable within a wellbore and configured to form a fluid seal between a first section of the wellbore and a second section of the wellbore, the second section of the wellbore located downhole from the first section of the wellbore, the fluid seal configured to provide a seal against a fluid pressure applied to the first section of the wellbore while isolating the second section of the wellbore from the fluid pressure; and a fluid pulse generator configured to controllably allow and block a flow of a fluid through or around the plug apparatus to thereby generate a fluid pulse signal in a column of the fluid that is injected into the first section of the wellbore as part of a stimulation procedure being performed on the wellbore. 
     Embodiment 2. The apparatus of embodiment 1, wherein the plug apparatus further comprises: a sealing member configured to seal an outside surface of the plug apparatus to an inner surface of a casing of the wellbore so that the fluid that is injected into the first section of the wellbore is prevented from passing around the outside surface of the plug apparatus once the plug apparatus is positioned at a desired location within the casing and the sealing member is activated to be in a sealing configuration. 
     Embodiment 3. The apparatus of embodiments 1 or 2, wherein the fluid pulse generator comprises: a stopper coupled to an actuator; the actuator configured to move the stopper between a first stopper position and a second stopper position, wherein when in the first stopper position the stopper blocks any fluid communication between the first section of the wellbore and the second section of the wellbore through one or more fluid passageways provided within the plug apparatus, and when in the second stopper position the stopper provides fluid communication between the first section of the well bore and the second section of the wellbore through the one or more fluid passageways provided within the plug apparatus. 
     Embodiment 4. The apparatus of embodiments 1 or 2, wherein the fluid pulse generator comprises: a siren positioned within the plug apparatus, the siren configured to provide one or more first siren positions that block any fluid communication between the first section of the wellbore and the second section of the wellbore through one or more fluid passageways provided within the plug apparatus, the siren further configured to provide one or more second siren positions that provide fluid communication between the first section of the wellbore and the second section of the wellbore through the one or more fluid passageways provided within the plug apparatus. 
     Embodiment 5. The apparatus of embodiment 4, wherein the siren further comprises: a first plate having one or more first plate fluid passageways extending through the first plate, and a second plate having one or more second plate fluid passageway extending through the second plate; and an actuator coupled to one or both of the first plate and the second plate, the actuator configured to position the first plate relative to the second plate so that no portion of the one or more first plate fluid passageways align with any portion of the one or more second plate fluid passageways when the siren is in the first siren position, and to position the first plate relative to the second plate so that at least some portion of the one or more first plate fluid passageways align at least one of the one or more second plate fluid passageways when the siren is in the second siren position. 
     Embodiment 6. The apparatus of any one of embodiments 1-5, wherein the fluid pulse generator is positioned within a portion of a wellbore casing extending between the first section of the wellbore and the second section of the wellbore and adjacent to the plug apparatus, the fluid pulse generator in fluid communication with one or more fluid passageways extending between the first section of the wellbore and the second section of the wellbore and around the plug apparatus, and wherein the fluid pulse generator is configured to controllably allow and block a flow of a fluid through the one or more fluid passageways and around the plug apparatus to thereby generate a fluid pulse signal in a column of the fluid that is injected into the first section of the wellbore. 
     Embodiment 7. The apparatus of any one of embodiments 1-2 and 6, wherein the fluid pulse generator comprises a fluid vortex coupled to a fluid diverter, the fluid diverter configured to shift a flow path of the fluid present in the first section of the wellbore between a first and second flow path extending through the fluid vortex in order to generate the fluid pulse signal in the column of the fluid that is injected into the first section of the wellbore. 
     Embodiment 8. The apparatus of any one of embodiments 1-5 and 7, wherein the fluid pulse generator is included in the plug apparatus configured to be pumped or dropped downhole into the wellbore in an orientation so that a sealing surface of the plug apparatus is orientated downhole relative to a front face of the plug apparatus and configured to be brought into physical contact with a sealing surface of a seat positioned within and attached to a casing of the wellbore in order to form the fluid seal between a first section of the wellbore and a second section of the wellbore. 
     Embodiment 9. The apparatus of any one of embodiments 1-8, wherein a column of the fluid injected into the first section of the wellbore as part of the stimulation procedure has a turbidity measurement of less than 1000 Formazin Nephelometric Units (FNU). 
     Embodiment 10. The apparatus of any one of embodiments 1-9, wherein the column of the fluid injected into the first section of the wellbore as part of the stimulation procedure being performed on the wellbore includes a fluid pressure in a range from 1,000 to 15,000 pounds per square inch. 
     Embodiment 11. The apparatus of any one of embodiments 1-10, wherein the fluid pulse signal comprises sensor data gathered at or near the plug apparatus while the plug apparatus is located within the wellbore and while during the stimulation procedure being performed on the wellbore. 
     Embodiment 12. A method comprising: injecting a treatment fluid into wellbore as part of a stimulation procedure being performed on the wellbore, the wellbore comprising a plug apparatus positioned within the wellbore, the plug apparatus forming a fluid seal between a first section of the wellbore and a second section of the wellbore, the second section of the wellbore located downhole from the first section of the wellbore, the fluid seal providing the fluid seal against a fluid pressure applied by the treatment fluid to the first section of the wellbore while isolating the second section of the wellbore from the fluid pressure; receiving, at a plug apparatus controller, one or more output signals from one or more downhole sensor located within the wellbore and positioned proximate to the plug apparatus; processing, using the plug apparatus controller, the one or more output signals to produce data; and actuating, using the plug apparatus controller, a fluid signal generator to produce a fluid pule signal in the treatment fluid, the fluid pulse signal including data produced based on the output signals. 
     Embodiment 13. The method of embodiment 12, wherein actuating the fluid signal generator comprises alternatively allowing and blocking a flow of the treatment fluid through or around the plug apparatus between the first section of the wellbore and the second section of the wellbore to generate a sequence of fluid pulses in a column of the treatment fluid present in the first section of the wellbore. 
     Embodiment 14. The method of embodiments 12 or 13, further comprising: detecting, at an acoustic receiver, the fluid pulse signal transmitted uphole to the acoustic receiver through a column of the treatment fluid present in first section of the wellbore; generating, using the acoustic receiver, and output signal corresponding to the fluid pulse signal detected by the acoustic receiver; and generating injection operation data based on output signal corresponding to the detected fluid pulse signal. 
     Embodiment 15. The method of embodiment 14, further comprising: performing one or more adjustments to the stimulation procedure being performed on the wellbore based at least in part on the injection operation data. 
     Embodiment 16. The method of any one of embodiments 12-15, wherein actuating the fluid signal generator to produce the fluid pulse signal in the treatment fluid comprises actuating a siren at a first frequency of operation to generate a first set of fluid pulses corresponding to a first data value and operation the siren at a second frequency of operation to generate a second set of fluid pulses corresponding to a second data value different from the first data value. 
     Embodiment 17. A system comprising: a plug apparatus positionable within a wellbore and configured to form a fluid seal between a first section of the wellbore and a second section of the wellbore, the second section of the wellbore located downhole from the first section of the wellbore, the fluid seal configured to provide the fluid seal against a fluid pressure applied to the first section of the wellbore while isolating the second section of the wellbore from the fluid pressure; a fluid pulse generator configured to controllably allow and block a flow of a fluid through or around the plug apparatus to thereby generate a fluid pulse signal in a column of the fluid that is injected into the first section of the wellbore as part of the stimulation procedure being performed on the wellbore; and a receiver positioned uphole from the fluid pulse generator, the receiver configured to detect the fluid pulse signal that has been transmitted through the column of the fluid that is injected into the first section of the wellbore, and to generate an output signal based in the detected fluid pulse signal. 
     Embodiment 18. The system of embodiment 17, wherein the plug apparatus comprises on or more sensor located proximate to or within the plug apparatus, the one or more sensors configured to measure one or more parameters associated with the fluid present in the wellbore, and to provide sensor output signals corresponding to the measured one or more parameters, wherein the fluid pulse generator is configured to generate the fluid pulse signal to include data based at least in part on the sensor output signals. 
     Embodiment 19. The system of embodiments 17 or 18, further comprising: a monitoring/control system configured to receive the output signal generated by the receiver, and to process the output signal to generate one or more control signals configured to provide control inputs to the stimulation procedure being performed on the wellbore. 
     Embodiment 20. The system of any one of embodiments 17-19, further comprising: an injection system comprising an injection controller coupled to control a mixing and pumping unit based at least in part on data provided by the fluid pulse signal, the mixing and pumping unit configured to provide the fluid that is injected into the first section of the wellbore as part of the stimulation procedure being performed on the wellbore.