Patent Publication Number: US-11649704-B2

Title: Processes and systems for injection of a liquid and gas mixture into a well

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority to U.S. Provisional Application No. 62/656,794, filed Apr. 12, 2018, and entitled Liquid Assisted Gas-Lift, the entire contents of which is incorporated by reference herein. 
    
    
     FIELD OF THE INVENTION 
     Processes and systems for injecting a liquid and gas mixture into a well are provided. 
     BACKGROUND OF THE INVENTION 
     Conventionally, various processes have been utilized to facilitate extraction of an oil and/or gas from a well. For instance, certain conventional artificial lift methods, such as a conventional gas lift method, have been utilized to initiate production. In certain processes, such conventional gas lift systems can be inefficient and resource intensive. It would be desirable to develop processes and systems that are more efficient, and that can increase well production. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWING 
         FIG.  1    is a schematic view of a well for illustrating various aspects of the processes and systems described herein. 
         FIG.  2    is a flow diagram illustrating one method for injection of a liquid and gas mixture into a well, in accordance with aspects described herein. 
         FIG.  3    is a flow diagram illustrating another method for injection of a liquid and gas mixture into a well, in accordance with aspects described herein. 
         FIG.  4    is a flow diagram illustrating yet another method for injection of a liquid and gas mixture into a well, in accordance with aspects described herein. 
         FIG.  5 A  is a top and side perspective view of an example system for use in implementing certain processes described herein, in accordance with aspects described herein. 
         FIG.  5 B  is a side view of the system of  FIG.  5 A , in accordance with aspects described herein. 
         FIG.  6    is a top and side perspective view of the frame assembly and side member supports of the example system of  FIG.  5 A , in accordance with aspects described herein. 
         FIG.  7    is a top and side perspective view of the example system of  FIG.  5 A  with the outer housing removed, in accordance with aspects described herein. 
         FIG.  8    is a top and side perspective view of the example system of  FIG.  2   , in the absence of the frame assembly and side member supports to show the liquid conduit, the gas conduit, the chemical additives source, the liquid pump, in addition to other components, in accordance with aspects described herein. 
         FIG.  9    is a diagrammatic depiction of the relative position of a liquid conduit, a gas conduit, a liquid pump, a chemical additives source, and additional components for use in a system to implement various aspects of processes described herein, in accordance with aspects described herein. 
         FIG.  10    depicts an example system adjacent to a well, where the liquid inlet of the system is in fluid communication with the interior of the production tubing of the well, and where the outlet of the system is in fluid communication with the annulus of the well, in accordance with aspects described herein. 
         FIG.  11    is a block diagram of an example system that includes an injection optimizer, in accordance with aspects described herein. 
         FIG.  12    is a block diagram of an example computing environment suitable to implement aspects described herein. 
         FIG.  13    is a flow diagram illustrating one method for injecting a mixture of a liquid and a gas into a well, in accordance with aspects described herein. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     Overview 
     In various aspects, processes and systems for injecting a liquid and gas mixture into a well are provided. In aspects, the processes can include injecting a liquid and gas mixture into a well to decrease the density of the production fluid. In such aspects, the decrease in density of the production fluid may enhance or increase production of the well. In the same or alternative aspects, the processes can include injecting a liquid and gas mixture into a well while the well is producing, and the injecting of the liquid and gas mixture may facilitate an increase in well production. 
     As noted above, certain conventional systems and processes, such as artificial gas lift systems, can be inefficient and resource intensive. For example in certain conventional gas lift systems, the source gas pressure can limit the depth at which the gas can be injected into the well, which may limit the ability of the gas lift process to effectively initiate extraction. Further, there is a need for processes and systems that can increase production of an already-producing well. 
     The systems and processes disclosed herein can alleviate one or more of these issues. For example, in certain aspects as described herein, it has been unexpectedly discovered that injecting a mixture of a liquid and a gas into a well that is currently producing can increase production of the well. In one aspect, injecting a mixture of a liquid and gas into a well that is currently producing can increase production of the well by about 5% to about 200%. 
     In further aspects, systems and processes disclosed herein that relate to the injection of a mixture of a liquid and a gas into a well can provide efficient enhanced well production while utilizing less resources than that required of a conventional process. For instance, the systems and process disclosed herein that relate to the injection of a mixture of a liquid and a gas can enhance production of a well using a deep-set valve (or no valve in some aspects), unlike in conventional systems that rely on multiple valves to kick off production as a way to inject the gas further downhole. Stated differently, the systems and processes disclosed herein can inject the mixture of the liquid and gas further downhole than what conventional processes are able to do, which can result in increased efficiency and/or increased well production compared to conventional gas lift processes. 
     Further as discussed below, the flow rate of the liquid and gas mixture and/or the compositional parameters of the mixture can be tailored based on identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. In such aspects, the processes and systems described herein can be optimized for specific well parameters and/or for specific identified production parameters, which can enhance production from the well and provide an efficient use of resources. 
     Accordingly, in one aspect a method for injection of a liquid and a gas mixture into a well is provided. The well can be producing a production fluid at a first production rate. The well can include a borehole extending into the ground to a formation, the borehole having at least one production tubing extending through at least a portion of the borehole. The method can include injecting a first mixture of a liquid and a gas into the well while the well is producing the production fluid at the first production rate, where the first mixture is injected at a first flow rate to cause the well to increase production of the production fluid to a second production rate that is greater than the first production rate. 
     In another aspect, a method for injection of a liquid and gas mixture into a producing well is provided. The well can include a borehole extending into the ground to a formation, the borehole having at least one production tubing extending through at least a portion of the borehole. The method can include injecting a first mixture of a liquid and a gas into the well while the well is producing a first volume of production fluid, the first volume of production fluid having a first density. The first mixture can be injected at a first flow rate thereby resulting in the formation of a second volume of production fluid, the second volume of production fluid having a second density that is less than the first density. 
     In yet another aspect, a computing device is provided. The computing device can have at least one processor and computer-readable instructions stored thereon. The computer-readable instructions, when executed by the at least one processor can cause the computing device to: identify one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters; and based on the identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, determine a first flow rate of a liquid, a gas, or a liquid and gas mixture, for injecting into a well to increase well production of a production fluid. 
     In another aspect, one or more nontransitory computer storage media is provided. The nontransitory computer readable media can store computer-useable instructions that, when used by one or more computing devices, cause the one or more computing devices to perform operations including: identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters; and based on the identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, determining a first flow rate of a liquid, a gas, or a liquid and gas mixture, for injecting into a well to increase well production of a production fluid. 
     Injection of a Liquid and Gas Mixture During Well Production: Processes and Mixture Parameters 
     As discussed above in certain aspects, the processes and systems described herein can include injecting a liquid and gas mixture into a well while the well is producing in order to increase production of the well. In aspects, a well that is producing or currently producing can refer to a well where a production fluid, such as oil and/or gas, is being extracted out of the well and to the surface. In one aspect, a well that is producing can refer to a well that is producing about one barrel of crude oil per day (bpd) or more, about five bpd or more, or about 15 bpd or more. 
     In certain aspects, injecting a liquid and gas mixture into a well while the well is producing can increase production of the well by about 5% or more, about 20% or more, about 30% or more, or about 50% or more. In the same or alternative aspects, injecting a liquid and gas mixture into a well while the well is producing can increase production of the well by about 5% to about 200%, about 10% to about 150%, or by about 20% to about 100%. It should be appreciated that an increase in well production is preferably described in terms of a percent increase in production, as such a measure is independent of the well parameters and/or reservoir parameters. In one aspect, injecting a liquid and gas mixture into a well while the well is producing can increase production of the well by about five bpd or more, about 10 bpd or more, or about 20 bpd or more. 
     In aspects, as discussed above, injecting a liquid and gas mixture into a well can decrease the density of the production fluid. In aspects, injecting a liquid and gas mixture into a well can decrease the density of the production fluid by about 5% or more, about 10% or more, or about 15% or more, or about 5% to about 50%, or about 5% to about 20%. 
       FIG.  1    depicts an example well  100  in relation to the processes described herein. The well  100  includes a borehole  102  that extends into the ground to a formation (not depicted in the figures). In the aspect depicted in  FIG.  1   , the borehole  102  includes a production tubing  110  extending through at least a portion of the borehole  102  and is adapted to permit production fluids, including but not limited to crude oil, to be extracted from the formation. Further, as can be seen in  FIG.  1   , there is a annulus  120  that is the space between the exterior  112  of the production tubing  110  and the surface  122  of the borehole  102 . 
     With continued reference to  FIG.  1   , in aspects, a mixture of the liquid and the gas may be produced and/or provided at a location adjacent the well  100 . In one aspect, one or more sources  140  can provide the liquid, the gas, and/or the mixture of the liquid and gas. In certain aspects, the one or more sources  140  can be present on the surface  141  of the ground adjacent the well  100 . In various aspects, the mixture of the liquid and the gas can be provided into the well  100  via a conduit  142 . 
     In the aspect depicted in  FIG.  1   , the conduit  142  is configured to provide the mixture into the annulus  120 . In such aspects, the mixture of the liquid and the gas may travel down the borehole  102  to a deep-set valve  130  coupled to the production tubing  110 , where the mixture is transported into the production tubing  110 , as indicated by the solid arrow extending down to the deep-set valve  130 . In an aspect not depicted in the figures, there may not be a valve at or near the bottom of the production tubing and the systems described herein can provide the mixture to the bottom of the production tubing where such mixture can enter the production tubing, as indicated by the dashed arrow extending down the annulus  120  and into the production tubing  110 . 
     It should be understood that while this one example well  100 , in relation to the processes described herein depicted in  FIG.  1   , describes the mixture of the liquid and the gas being injected into the annulus  120  and ultimately into the production tubing  110  to facilitate extraction of production fluids by traveling through the production tubing  110  and out of the well  100 , an alternative operation is also contemplated by the systems and processes described herein. For instance, in one aspect, the gas and liquid mixture can be injected directly into the production tubing  110  and thereby travel downhole and enter the annulus  120  via a valve or bottom of the tubing to facilitate extraction of production fluids out and through the annulus  120 . 
     In certain aspects, as discussed above, a mixture of a liquid and a gas is injected into a well, e.g., the well  100  of  FIG.  1    to increase production of the well. In one or more aspects, without being bound by any particular theory it is believed that the mixtures described herein, when injected, can decrease the density of at least a portion of the production fluid in the well, which in turn can increase well production, e.g., by releasing additional pressure from the reservoir. 
     In aspects, the liquid can include water, hydrocarbons, or a combination thereof. In aspects, the hydrocarbons can include crude oil. In the same or alternative aspects, the liquid can include a production fluid, e.g., a crude oil, produced from the well where the injection process is occurring. In a preferred aspect, the liquid includes crude oil. 
     In certain aspects, the gas can include hydrocarbons, air, or a combination thereof. In various aspects, the gas can include methane, ethane, propane, butane, air, or a combination thereof. In a preferred aspect, the gas includes methane. 
     In certain aspects, the gas can be present in the mixture in an amount of from 10% by volume of the mixture to 99% by volume of the mixture, 30% by volume of the mixture to 95% by volume of the mixture, or 40% by volume of the mixture to 85% by volume of the mixture. In such aspects, the volume of the gas in the mixture refers to the mole fraction volume as determined at standard temperature and pressure. 
     In aspects, one or more chemical additives can optionally be added to the liquid and gas mixture for one or more purposes. For instance in one aspect, the chemical additives can include surfactants, de-emulsifiers, emulsifiers, drag reducing agents, or other chemical additives known to have an impact on multiphase flow and the pattern of flow, such as impacting the transition from one flow pattern to another. In the same or alternative aspects, the chemical additives can include chemical additives that are known to reduce the required surface injection pressures, to reduce the amount of fluid co-injected with the gas in the downward annular injection flow. In various aspects, the chemical additives can include chemical additives that are known to alter the flow in the production string downstream of the gas or mixture injection point and to alter the flow in a horizontal and near-horizontal sections of pipe such as the horizontal well. In the same or alternative aspects, the chemical additives can include scale inhibitors and/or corrosion inhibitors. In aspects, the chemical additives can include chemical additives that are different than the liquid being utilized the liquid and gas mixture. 
     Returning now to  FIG.  1   , as noted above, in certain aspects, the liquid may include a production fluid, e.g., a crude oil, produced from the well where the injection process is occurring. In aspects, a conduit  152  is coupled to the production tubing  110 , which can provide a stream of the production fluid, e.g., a crude oil, for further use in the injection processes described herein. As can be seen in  FIG.  1   , the production fluid from the well, e.g., via the conduit  152 , can be optionally exposed to one or more post-production systems or processes, e.g., one or more post-production processes  150  of  FIG.  1   , prior to its use in the injection processes. In such an aspect, the production fluid may exit the one or more post-production systems or processes  150  via a conduit  154  and be returned to the one or more sources  140 . A non-limiting list of post-production systems and processes includes the use of one or more separators to remove water, other liquids, and/or gas, and the use of a storage vessel from which the crude oil can be withdrawn. 
     As discussed above, in various aspects, the processes disclosed herein can include injecting a mixture of a liquid and a gas into a well in order to increase production of the well. In certain aspects, the mixture of the liquid and the gas can be formed using equipment that is convenient for use in an oil well setting. Example systems that can be utilized to perform the processes described herein are described further below with reference to  FIGS.  5 A- 12   . Prior to discussing these example systems, the processes will be further described. 
       FIG.  2    depicts a flow diagram illustrating a method  200  for injection of a liquid and a gas mixture into a well. In aspects, the processes disclosed herein can include injecting a liquid and gas mixture into a well while the well is producing a production fluid. In one aspect, the production fluid can include oil and/or gas. At step  210 , the method  200  can include determining a first production rate or production amount of the production fluid at a first time. In such aspects, the production rate or amount may be monitored using any convenient flow meter of flow gauge. In one or more aspects, the initial production rate of the well may be determined in order to discern a baseline or average production level, e.g., in order to determine when production increases from such a baseline level, or to determine when to adjust injection parameters as discussed further below. Alternately, or in addition, at step  210 , the bottom hole pressure can be determined, e.g., using any convenient pressure gauge suitable for use in a well downhole. In aspects, the bottom hole pressure can be measured in a region near a deep-set valve, or at or near the bottom of the production tubing, e.g., within 30 meters, within 20 meters, or within 10 meters of such a deep-set valve or bottom of the production tubing. Additionally or alternatively, in aspects, the bottom hole pressure can be estimated based on the flow rate of the liquid, the flow rate of the gas, and the well geometry parameters, which are discussed further below with respect to an example injection system. 
     At step  220 , the method  200  can include injecting a first mixture of a liquid and a gas into the well. The mixture, the liquid, and the gas can have any or all of the respective parameters discussed above for the mixture, liquid, and/or the gas. For instance in one aspect, the liquid can include crude oil, and the gas can include methane. In a further aspect, at least a portion of the crude oil present in the mixture can include a crude oil derived from the production fluid of the well at a time prior to injecting the mixture into the well. 
     At step  230 , the method  200  can include determining a second production rate or production amount of the production fluid at a second time. In one aspect, the second production rate or production amount is determined subsequent to injecting the mixture of the liquid and the gas into the well performed at the step  220 . In aspects, the second production rate can be determined in a manner similar to that described above with respect to the step  210 . Further, in an alternate aspect or in addition, the step  230  may include determining bottom hole pressure in a manner similar to that described above with respect to the step  210 . In aspects, the second production rate may be increased relative to the first production rate. In such aspects, the increase in production rate can be similar to that described above. For instance, the second production rate or amount can be increased by about 5% or more, about 20% or more, about 30% or more, or about 50% or more; or of from about 5% to about 200%, about 10% to about 100%, by about 20% to about 100%, or by about 20% to about 50%. 
     At step  240 , the method can include injecting a second mixture of the liquid and the gas into the well. In aspects, the step  240  can occur subsequent to one or more of the steps  210 ,  220 , or  230 . In various aspects, as discussed above, it may be desirable to reduce the bottom hole pressure and/or the pressure in the production tubing in an effort to increase production. Furthermore, in various aspects, it may be beneficial to minimize the amount of liquid being injected into the well, e.g., while the well is producing in an effort to conserve resources. In such aspects, the second mixture injected at step  240  may comprise a reduced amount of the liquid compared to the first mixture injected at the step  210 , e.g., in order to increase the production rate of the production fluid or production amount and/or to decrease the bottom hole pressure. In the same or alternative aspects, the first mixture injected at the step  210  may comprise an increased amount of gas relative to the second mixture injected at the step  240 , e.g., in order to increase the production rate of the production fluid or production amount and/or to decrease the bottom hole pressure. 
       FIG.  3    depicts a flow diagram illustrating a method  300  for injection of a liquid and a gas mixture into a well. In aspects, the mixture of the liquid and gas can be injected into a well that is producing a production fluid. In one aspect, the production fluid can include oil and/or gas. In one aspect, the well can include a borehole extending into the ground to a formation, where the borehole comprises at least one production tubing extending through at least a portion of the borehole, such as that depicted in  FIG.  1   . 
     At step  310 , the method  300  can include injecting a mixture of a liquid and a gas into the well. In certain aspects, injecting a mixture of a liquid and a gas into the well of step  310  can occur while the well is producing a production fluid at a first production rate. In various aspects, the mixture, the liquid, and/or the gas can have any or all of the respective parameters discussed above for the mixture, liquid, and/or the gas. For instance in one aspect, the liquid can comprise crude oil, and the gas can include methane. In a further aspect, at least a portion of the crude oil present in the mixture can include a crude oil derived from the production fluid of the well at a time prior to injecting the mixture into the well. In various aspects, as discussed above gas can be present in the mixture in an amount of from 10% by volume of the mixture to 99% by volume of the mixture, 30% by volume of the mixture to 95% by volume of the mixture, or 40% by volume of the mixture to 85% by volume of the mixture. 
     In various aspects, the mixture of the liquid and the gas is injected at a first flow rate to cause the well to produce the production fluid at a second production rate that is greater than the first production rate. In such aspects, the increase in production can include any or all of the parameters for increasing production of a well discussed above. For instance, in aspects, injecting the mixture into the well can increase production of the production fluid by about 5% to about 200%, about 10% to about 150%, or by about 20% to about 100%; and/or may increase production of the production fluid by about five bpd or more, about 10 bpd or more, or about 20 bpd or more. 
       FIG.  4    depicts a flow diagram illustrating a method  400  for injection of a liquid and a gas mixture into a well. In aspects, the mixture of the liquid and gas can be injected into a well that is producing a production fluid. In one aspect, the production fluid can include oil and/or gas. In one aspect, the well can include a borehole extending into the ground to a formation, where the borehole comprises at least one production tubing extending through at least a portion of the borehole, such as that depicted in  FIG.  1   . 
     At step  410 , the method  400  can include injecting a mixture of a liquid and a gas into the well. In aspects, injecting a mixture of a liquid and a gas into the well of step  410  can occur while the well is producing a first volume of production fluid having a first density. In various aspects, the mixture, the liquid, and/or the gas can have any or all of the respective parameters discussed above for the mixture, liquid, and/or the gas. For instance in one aspect, the liquid can comprise crude oil, and the gas can include methane. In a further aspect, at least a portion of the crude oil present in the mixture can include a crude oil derived from the production fluid of the well at a time prior to injecting the mixture into the well. In various aspects, as discussed above gas can be present in the mixture in an amount of from 10% by volume of the mixture to 99% by volume of the mixture, 30% by volume of the mixture to 95% by volume of the mixture, or 40% by volume of the mixture to 85% by volume of the mixture 
     In various aspects, the mixture of the liquid and the gas can be injected at a first flow rate resulting in the well producing a second volume of production fluid having a second density. In such aspects, the second density of the second volume of production fluid can be less than the first density of the first production fluid. In certain aspects, the decrease in density of the production fluid can include any or all of the decrease in density parameters discussed above. For example, in aspects, injecting a mixture of a liquid and a gas into the well can decrease the density of the production fluid by about 5% or more, about 10% or more, or about 15% or more, or of from about 5% to about 50%, or of from about 5% to about 20%. 
     In aspects, the decrease in density of the production fluid may also increase overall well production. For instance in such aspects, injecting the mixture into the well can increase production of the production fluid by about 5% to about 200%, about 10% to about 150%, or by about 20% to about 100%; and/or may increase production of the production fluid by about five bpd or more, about 10 bpd or more, or about 20 bpd or more. 
     As discussed above in certain aspects, the mixture of the liquid and the gas is injected into the well at a flow rate optimized or tailored to cause the well to increase production, to decrease the density of the production fluid, and/or to decrease the downhole pressure. In various aspects, the flow rate of the mixture of the liquid and the gas can be determined based on the example systems and processes described below. For instance in aspects discussed further below, the flow rates of the liquid, the gas, and/or the mixture, and the relative amounts of the liquid and/or gas can be tailored in the mixture to facilitate increased well production, decrease the density of the production fluid, and/or to decrease downhole pressure. In one example, if too little liquid is present in the mixture, then there may be insufficient hydrostatic pressure to allow gas to be circulated to the tubing or downhole injection point. Further, in certain aspects, if too little gas is present in the mixture, the downhole pressure and/or the density of the production fluid may not decrease to a desired level, e.g., a level that may facilitate increased well production. In addition, in various aspects, the liquid injection rate can be tailored to create sufficient mixture velocity to carry gas bubbles downward to a deep-set valve. 
     As discussed above, in certain aspects, the relative amounts of the gas and liquid in the mixture and/or the flow rate of the mixture can be tailored to facilitate increased well production. Additionally or alternatively, in certain aspects, the relative amounts of the gas and liquid in the mixture and/or the flow rate of the mixture can be tailored based on identifying one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. Certain well geometry parameters, well productivity parameters, produced fluids properties, and surface production parameters are described in: Brill, J. P., &amp; Mukherjee, H. K. (1999)  Multiphase Flow in Wells , Society of Petroleum Engineers, SPE Monograph Series Vol. 17, ISBN: 978-1-55563-080-5, the entirety of which is incorporated by reference herein; and in Shoham, O. (2006)  Mechanistic Modeling of Gas - Liquid Two - Phase Flow in Pipes , Society of Petroleum Engineers, ISBN 978-1-55563-107-9, the entirety of which is incorporated by reference herein. 
     In various aspects, the well geometry parameters can include any physical parameters of the well, or associated tubing, casings, or the like found in conventional oil wells. In certain aspects, a non-limiting list of well geometry parameters includes: an internal diameter of well tubing, an external diameter of well tubing, an internal diameter of a casing string, a depth of the casing string, an inclination of the casing string, a diameter of the vertical wellbore section, depth of the vertical section, depth of the injection valve, or a combination thereof. 
     In aspects, the produced fluids properties can include any properties or parameters associated with the fluids produced or extracted from the well. In certain aspects, a non-limiting list of the produced fluids properties includes: a density of the well-produced fluids, an API gravity of the produced fluids, such as an API gravity of the oil or condensate, a viscosity of the well-produced fluids, a pressure of the well-produced fluids, a volume of the well-produced fluids, a temperature of the well-produced fluids, or a combination thereof. 
     In various aspects, the well productivity parameters can include parameters and/or properties associated with the productivity of the well. In certain aspects, a non-limiting list of the well productivity parameters includes an average reservoir pressure, a flow potential for the well, recent production rates from the well, such as 30 day average of an oil or condensate rate (barrels per day), a 30 day average water rate (barrels per day), a 30 day average gas rate (thousand standard cubic feet per day-mscf/D), a flowing tubing pressure, a well head pressure, a choke setting, a well head flowing temperature, or a combination thereof. 
     In aspects, the surface production parameters can include properties and/or parameters associated with the gas source, the liquid source, or the mixture of the liquid and gas being injected into the well or to be injected into the well. In the same or alternative aspects, the surface production parameters can include well head or casing head properties. In certain aspects, a non-limiting list of the surface production parameters includes: a gas conduit pressure, a liquid conduit pressure, an injection point pressure, a liquid and gas mixture conduit pressure, an outlet pressure, a well head shut-in pressure, a well head shut-in temperature, a production line pressure, a separator pressure, a casing head shut-in temperature, a casing head shut-in pressure, the gas volume available or extractable from the gas source, source gas pressure, or a combination thereof. 
     In aspects, the relative amounts of the gas and liquid in the mixture and/or the flow rate of the mixture can be tailored based on identifying one or more of: a diameter of the vertical wellbore section, depth of the vertical section, the gas volume available or extractable from the gas source, source gas pressure, an API gravity of the produced fluids, such as an API gravity of the oil or condensate, oil or condensate average rate (barrels per day), a water average rate (barrels per day), a gas average rate (thousand standard cubic feet per day-mscf/D), or a flowing tubing pressure. 
     In certain aspects, the liquid and/or gas injection or flow rates sufficient to facilitate downward bubble flow in the well can be determined based on one or more of the properties discussed above, e.g., the well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. As discussed further below, in various aspects, the downward bubble flow in the well can be facilitated to occur in the tubing casing annulus or annulus of the well, such as for example the annulus  120  of  FIG.  1   . In an alternative aspect, downward bubble flow in the well can be facilitated to occur in the tubing of the well. 
     In various aspects, optimizing the liquid and/or gas flow rates may employ the determination of various properties associated with the well or the injection system and/or may employ specific control methods of the injection system and processes disclosed herein. For instance, in certain aspects, one or more of the following may be performed to aid in tailoring the flow rate of the liquid and the gas to achieve increased well production: calculating the flow rate sufficient to facilitate downward bubble flow in the tubing casing annulus: calculating the minimum liquid weight required to achieve circulation of gas into the tubing in light of the source gas pressure; calculating the (gas) bubble rise velocity at multiple points in the tubing casing annulus; calculating the fluid levels in the casing or tubing in order to assign various flow regimes; tailoring the flow of the liquid and/or the gas to provide various patterns of high and/or low liquid injection rates. The determination of one or more of these parameters is further discussed below. 
     A multiphase flow correlation and/or model can be used for downward multiphase flow, such as, but not limited to, the Beggs &amp; Brill correlation shown in equation (1) below. In such aspects, this correlation can aid in determining the liquid and gas injection rates at the surface required to achieve downward bubble flow in the tubing-casing annulus. In such aspects, a minimum liquid velocity must be achieved for injected gas lift gas to move downward can be determined.
 
 F   DRAG   ≥F   BUOYANCY   (1)
 
     In aspects, where chemical additives, such as the chemical additives discussed above are utilized, a homogeneous flow model may be utilized to identify both frictional and gravitational pressure changes in the annulus of the well with the formulas of equations (2), (3), (4), and (5) shown below. This flow model may be utilized to aid in determining the liquid and gas injection rates at the surface required to achieve downward bubble flow in the tubing-casing annulus. 
     
       
         
           
             
               
                 
                   
                     
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                       Q 
                       L 
                     
                     
                       
                         Q 
                         L 
                       
                       + 
                       
                         Q 
                         G 
                       
                     
                   
                 
               
               
                 
                   ( 
                   5 
                   ) 
                 
               
             
           
         
       
     
     Q L  is the liquid volumetric flow rate at in-situ conditions, Q G  is the gas volumetric flow rate at in-situ conditions, g is the acceleration of gravity, g c  is the gravitation constant and θ is the inclination of the pipe, f m  is the mixture friction factor, v m  is the velocity of the two-phase mixture at in-situ conditions, d is the diameter of the pipe, λ L  is the no-slip liquid holdup, ρ L  is in-situ liquid density, ρ G  is the in-situ gas density and ρ m  is the in-situ mixture density. In aspects, in-situ conditions refers to conditions during operation of the processes disclosed herein. 
     In one or more aspects as discussed above, the fluid level in the casing/tubing can be determined and one or more flow regimes can be assigned for use. In such aspects, flow modeling can be done for the various regimes of the pipe which may be present in the well at startup which may be assigned single-phase gas, single-phase liquid, and multiphase (e.g., gas and liquid) designations. This may be done by comparing shut-in wellhead pressures with estimated reservoir pressure, for instance as with equation (6) below.
 
 P   CHSI   =P   res − ρ   L [ D   bh   −D   LL ]− ρ   G [ D   LL ]  (6)
 
     P CHSI  is the Casing-Head Shut-In Pressure, P res  is the average reservoir pressure or an approximation of the buttonhole pressure at shut-in conditions just prior to starting the artificial lift procedure, ρ L  is liquid density, ρ G  is gas density and D bh  is the Total Vertical Depth to the reservoir perforations or intake point, and D LL  is the depth to the liquid level in the tubing-casing annulus. 
     In one or more aspects, utilizing one or more of the well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, one can determine the gas bubble rise velocity at one or more points in the tubing-casing annulus to ensure that the gas will move downward in the tubing-casing annulus to a deep-set valve. In such aspects, the gas bubble rise velocities can be utilized to determine flow or injection rates of the liquid and gas mixture to create suitable conditions for downward movement of the gas and/or the liquid and gas mixture. 
     In aspects, based on one or more of the well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, one can identify flow patterns for the liquid, gas, or mixture thereof in order to create a specific environment in the tubing-casing annulus for downward movement of the injected gas such that the bubble rise velocity is exceeded by the downward velocity of the liquid and gas mixture. In other words, the relative amounts of gas and liquid injected are important to establish the proper downward multiphase flow pattern to both create the proper hydrostatic, or weight, and achieve a velocity and flow pattern for downward flow of the gas-liquid mixture. 
     Above, various determinations are described that generally may be associated with the tailoring of the liquid and/or gas flow rate to achieve downward movement of the gas and, e.g., into the production tubing. In various aspects, one or more of the tubing head pressure, tubing head temperature, casing head pressure, or casing head temperature may be monitored in order to modify the injected gas and liquid rates to ensure the gas is circulated through the deep-set valve or around the bottom of the tubing if no valve is used. In such aspects, if casing head pressures increase beyond an expected threshold, additional liquid can be injected to add additional “weight” to keep below the maximum gas source pressure. Further, in such aspects, iterations may be performed between the injection flow pattern calculations and the integrated “weight” history injected during the kick-off process. 
     In certain aspects as discussed above, it may be desirable to minimize the use of the liquid being injected into the well. For instance, in certain aspects, the liquid injection rate may be initially high in order to facilitate the downward movement of the gas; however, once the gas enters the production tubing, it may be desirable to reduce the injection rate of the liquid. In aspects, prior to changing the liquid flow rate, gas entry into the tubing may be detected through monitoring one or more parameters, such as the tubing head pressure and temperature. For instance, an increase in flowing tubing head pressure may indicate a drop in density of fluids in the tubing string or production tubing caused by the entry of gas. In the same or alternative aspects, the multiphase flow calculations and the monitoring of the casing head pressure may be utilized to detect or determine gas entry into the tubing. For example, a decrease in injection casing head pressure may indicate a drop in density of fluids in the tubing string caused by the entry of gas, multiphase flow velocities can be utilized to determine the time when gas reaches the valve or end-of-tubing if no valve is used, and/or multiphase flow correlations can be utilized to determine the pressure at the injection point by calculating upward flow in the tubing utilizing the measured wellhead tubing flowing pressure. 
     In aspects, once the gas enters the tubing, an optional adjustment of the liquid injection rate may be pursued. In such aspects, the reduction in liquid injection rates or ramping down can be performed in part by monitoring both the wellhead tubing and casing pressures so that the appropriate parameters are present to maintain gas entry in the production tubing. Further in such aspects, a non-limiting list of various methods for ramping down the liquid injection rate while maintaining the gas entry into the tubing includes: iterating the weight of the fluid column with the wellhead tubing and casing pressures to maintain injection at the downhole injection point; utilizing multiphase flow correlations to predict the pressure at the gas injection point in the tubing (either at the single deep-set valve or at the end of the tubing) and iterating this the downward flow calculation to match the input flowing tubing head pressure and casing head injection pressure; or switching the liquid rates from high to low levels to create slugs of single-phase liquid, bubble or slug/churn flow that travel downward separated by gas bubbles. 
     Example Injection Systems 
       FIGS.  5 A- 8    depict one example system  500  for injecting a liquid and gas mixture into a well, e.g., to increase production in a well. It should be understood that the system  500  depicted in  FIGS.  5 A- 8    is just one example injection system and that other systems and configurations of the components are contemplated by the disclosure herein. Starting with  FIGS.  5 A and  5 B , the exterior portion of housing  510  and a portion of the frame assembly  520  for this example system is depicted. As best seen in  FIG.  5 B , in aspects, the system  500  can also include one or more of a power distribution system  530 , a variable frequency drive  540 , and a computing device  550 . The power distribution system  530 , the variable frequency drive  540 , and the computing device  550  will be discussed further below. In certain aspects, the system  500  can be mobile and is capable of being transported to and from a well, and/or transported from one well to another well. In aspects, the system  500  is sized to fit on a flatbed trailer of an 18-wheel tractor trailer. In such aspects, the system  500  can have a length l, as identified in  FIG.  5 A , of from 1.5 meters (m) to 24 m; 2.4 m to 21 m, or 3 m to 17 m. In the same or alternative aspects, the system  500  can have a width w, as identified in  FIG.  5 A , of from 0.3 m to 6 m; 0.6 m to 4.5 m, or 0.9 m to 3.7 m. In various aspects, the system  500  can have a height h, as identified in  FIG.  5 A , of from 0.3 m to 6 m; 0.6 m to 4.5 m, or 0.9 m to 3.7 m. In certain aspects, the system  500  has a mass of from 700 kilograms (kg) to 50,000 kg, from 900 kg to 30,000 kg, or from 1100 kg to 15,000 kg. 
     In aspects, as discussed above, the system  500  can be transported from one location to another location. In such aspects, the frame assembly  520  can be adapted to transport the system  500  from one location to another. For example, as can be seen in  FIGS.  5 A and  5 B , the frame assembly  520  can include voids  522  for engaging with a transport device, such as a forklift or crane. In aspects, the frame assembly  520  comprises a metal material that is capable of supporting and transporting the system  500  having a weight of from 700 kg to 50,000 kg, 900 kg to 30,000 kg, or 1100 kg to 15,000 kg. In one aspect, the system  500  can be configured for transport on a trailer. 
       FIG.  6    depicts the frame assembly  520  for the system  500 . In the aspect depicted in  FIG.  6   , the frame assembly  520  includes a base member  524 , a plurality of side support members  526  extending up from the base member  524 , and a top support member  528 . As discussed above, in aspects, the frame assembly  520  can include voids  522  that can be utilized to lift and/or move the system  500 . In such aspects, the voids  522  may be defined the base member  524 . It is understood that the voids  522  are just one example way that the frame assembly  520  is adapted to transport the system  500  from one location to another and that other modifications and/or additions to the frame assembly  520  that are capable of facilitating the transport of the system  500  are also contemplated by the disclosure herein. 
       FIG.  7    depicts the frame assembly  520  and additional components of the system  500  coupled to the frame assembly  520 . In certain aspects, one or more of the additional components of the system  500  can be coupled to the base member  524 . In aspects, as discussed further below, the one or more additional components that are coupled to the frame assembly  520  can include, but are not limited to, a gas conduit  560 , a liquid conduit  570 , a liquid pump  574 , a first mixer  580 , and an outlet  582 . Additional components and associated connections are discussed further below with reference to  FIG.  8   . 
     As can be seen in the aspect depicted  FIG.  7   , at least the gas conduit  560 , the liquid conduit  570 , the liquid pump  574 , and the first mixer  580  are coupled to the frame assembly  520  via the base member  524 . In the same or alternative aspects, at least the gas conduit  560 , the liquid conduit  570 , the liquid pump  574 , and the first mixer  580  are coupled to and are positioned within the frame assembly  520  such that at least the gas conduit  560 , the liquid conduit  570 , the liquid pump  574 , and the first mixer  580  are positioned in an interior volume  511  of the housing, e.g., the housing  510  of  FIG.  5 A . 
       FIG.  8    depicts the additional components of the system  500  also illustrated in  FIG.  7    but in the absence of the frame assembly  520 . As can be seen in  FIG.  8   , the system  500  can include, but is not limited to, a gas conduit  560 , a liquid conduit  570 , a liquid pump  574 , a first mixer  580 , and an outlet  582 . 
     In the aspect depicted in  FIG.  8   , the gas conduit  560  can extend between a gas intake  562  at a first gas conduit end  563  and a first mixer  580  at a second gas conduit end  565 . In aspects, the gas conduit  560 , via the gas intake  562 , can be coupled to a source gas. As discussed above, in various aspects, the source gas can include hydrocarbons, air, or a combination thereof. In various aspects, the gas can include methane, ethane, propane, butane, air, or a combination thereof. In a preferred aspect, the gas includes methane. In various aspects not depicted in the figures, a control valve can be placed between the gas supply and the gas intake. For example, the control valve may facilitate connection to a customer provided gas supply. In the same of alternative aspects not depicted in the figures, a choke valve can be placed between the gas supply and the gas intake  562  to control the gas flowing into the gas conduit  560  and the system  500 . In such aspects, a computing device, e.g., the computing device  550  of  FIG.  5 B , may operate or direct the operation of such a choke valve. 
     In one or more aspects, the gas conduit  560 , via the gas intake  562 , may direct the gas communicated from the gas source through a gas flow meter  566  and a gas valve  567  to the first mixer  580 . In aspects, the gas communicated from the gas source can be pressurized. In certain aspects, a gas pressure gauge sensor  568 , a gas temperature gauge sensor  569 , or both can be coupled to the gas conduit  560  at a position between the gas intake  562  and the first mixer  580 . In various aspects, the gas pressure gauge sensor  568 , the gas temperature gauge sensor  569 , or both can be adapted to provide gas temperature and/or gas pressure information to a computing device, e.g., the computing device  550  of  FIG.  5 B , where such information can be utilized in the processes described herein. 
     In the aspect depicted in  FIG.  8   , the liquid conduit  570  can extend from the liquid intake  572  at a first end  573  to the first mixer  580  at a second end  575 . As discussed above, the liquid can include water, hydrocarbons or a combination thereof. In one aspect, the hydrocarbons can include a crude oil. In the same or alternative aspects, the liquid can include a crude oil produced from the well where the artificial lift process is occurring. 
     In aspects, the liquid conduit  570   a  may direct the liquid communicated from the liquid source to the liquid pump  574 . In the aspect depicted in  FIG.  8   , a pressure gauge  576  may be positioned between the liquid intake  572  and the liquid pump  574  to measure the pressure of the liquid line upstream of the liquid pump  574 . In such aspects, the liquid pump  574  may be configured to pump the liquid and/or the liquid and gas mixture through the liquid pump exit conduit  570   b  and on through the remaining portion of the system components and out through the outlet  582  to a well. In an aspect not depicted in  FIG.  8   , a valve may be coupled to the outlet  582 . 
     In aspects, the liquid pump  574  can include an electric motor. In such aspects, a variable frequency drive, e.g., the variable frequency drive  540  of  FIG.  1 B , may control the amount of power going into the electric motor of the liquid pump  574  in order to control the flow rate of the output liquid. In such aspects, a computing device, e.g., the computing device  550  of  FIG.  5 B , can operate or direct the operation of the variable frequency drive. 
     In aspects, a recirculation conduit  571  can optionally be included in order to aid in controlling the pressure in the liquid pump exit conduit  570   b . In such aspects, the use of the recirculation conduit  571  can allow for the control of the pressure and flow rate independent of one another. As can be seen in the aspect depicted in  FIG.  8   , a pump discharge pressure gauge  570   c  may be coupled to the liquid pump exit conduit  570   b  and adapted to monitor the pressure of the pump discharge in the liquid pump exit conduit  570   b . In aspects, a recirculation liquid control valve  579  can permit or block the recirculation of the liquid from the liquid pump exit conduit  570   b  and through the recirculation conduit  571 , which may be returned to a liquid source or a holding vessel. In aspects, a computing device, e.g., the computing device  550  of  FIG.  5 B , can operate or direct the operation of the recirculation liquid control valve  579 . 
     In aspects, as discussed above, chemical additives can optionally be added to the liquid and gas mixture. For instance, in the aspect depicted in  FIG.  8   , a chemical additives source  592  can be coupled to a second mixer  584 . Further, in the aspect depicted in  FIG.  8   , a chemical pump  590  can be coupled to the chemical additives source  592  to supply the chemical additives to the second mixer  584  and the liquid in the liquid conduit  570 . In certain aspects, the chemical pump  590  can be driven by an electric motor. In such aspects, a variable frequency drive, e.g., the variable frequency drive  540  of  FIG.  5 B , may control the amount of power going into the electric motor of the chemical pump  590  in order to control the flow rate of the output liquid. In such aspects, a computing device, e.g., the computing device  550  of  FIG.  5 B , can operate or direct the operation of the variable frequency drive. 
     In aspects, the chemical additive source  592  can be a tank of one or more chemical additives that is housed within an interior volume of the system housing, e.g., the housing  510  of  FIG.  5 A . In alternative aspects not depicted in the figures, a chemical additives source can be exterior to the system and can be provided to the system via a chemical conduit. In various aspects, the chemical additives source  592  (and/or an exterior chemical additives source) can include a meter and valve for controlling the rate of chemical additives addition to the liquid in the liquid conduit or the mixture of the liquid and the gas. 
     In aspects, the chemical additives can include any conventional chemical additives utilized in well extraction processes. For instance in one aspect, the chemical additives can include surfactants, de-emulsifiers, emulsifiers, drag reducing agents, or other chemical additives known to have an impact on multiphase flow and the pattern of flow, such as impacting the transition from one flow pattern to another. In the same or alternative aspects, the chemical additives can include chemical additives that are known to reduce the required surface injection pressures, to reduce the amount of fluid co-injected with the gas in the downward annular injection flow. In various aspects, the chemical additives can include chemical additives that are known to alter the flow in the production string downstream of the gas lift injection point and to alter the flow in a horizontal and near-horizontal sections of pipe such as the horizontal well. In the same or alternative aspects, the chemical additives can include scale inhibitors and/or corrosion inhibitors. In aspects, the chemical additives can include chemicals additives that are different than the liquid being utilized the liquid and gas mixture. 
     In certain aspects, the liquid being pumped in the liquid conduit  570  can be transported to the first mixer  580  where the liquid (and optionally any chemical additive(s)) is mixed with the gas from the gas conduit  560  prior to being transported to the well via the outlet  582 . In aspects, a liquid valve  583  may be placed upstream of the first mixer  580 , e.g., between the liquid intake  572  and the first mixer  580 , to control the flow rate of the liquid entering the first mixer  580  and/or exiting the outlet  582 . In aspects, the liquid valve  583  may be used when disconnecting the system from the well. In aspects, a computing device, e.g., the computing device  550  of  FIG.  5 B , can operate or direct the operation of the liquid valve  583 . 
     In aspects, the first mixer  580  can be configured to mix the liquid and the gas into a multiphase mixture, e.g., a mixture of the liquid and the gas. In one example aspect depicted in  FIG.  8   , the first mixer  580  can be a T-conduit fluidly coupled to the gas conduit  560  and the liquid conduit  570 . The first mixer  580  can be any other type of convenient mixer for mixing a liquid and a gas, including but not limited to a Y-shaped conduit or sphere-shaped conduit. In the same or alternative aspects, the first mixer  580  can include one or more internal baffles in the conduit to facilitate efficient mixing of the liquid and the gas. In yet another aspect, the first mixer  580  may be configured to include a gas diffuser or sparger. It is appreciated that the second mixer  584  can include any or all of the properties and parameters of the first mixer  580  discussed herein. 
     In certain aspects, once the liquid and the gas is converted into the mixture of the liquid and the gas in the first mixer  580 , the mixture can be transported via a mixture conduit  585  to the outlet  582  and ultimately to the well. In aspects, one or more temperature and/or pressure gauges, e.g., pressure gauge  587  may be positioned in the mixture conduit  585  for providing such information to a computing device, e.g., the computing device  550  of  FIG.  5 B . 
       FIG.  9    depicts another example of a configuration for use in the systems and processes disclosed herein. As can be seen in the aspect depicted in  FIG.  9   , a gas conduit  610  can be coupled to a gas source  620  via a gas intake  612 . Further in the aspect depicted in  FIG.  9   , the gas conduit  610  can include a liquid meter  613  placed between needle valves  615 . Additionally in aspects, the gas conduit  610  can include a gas flow control valve  614  between the gas source  620  and the first mixer  619 . In various aspects, a check valve  616  can be positioned along the gas conduit  610  between the gas flow control valve  614  and the first mixer  619  in order to prevent backflow from the first mixer  619  into the gas conduit  610 . In aspects, the gas source  620  can include one or more of the gases mentioned above for use in the injection systems and processes disclosed herein. In various aspects one or more of the liquid meter  613 , the gas flow control valve  614 , or the check valve  616  can be in communication with a computing device, e.g., the computing device  550  of  FIG.  5 B . In such aspects, the computing device can operate or direct the operation of the gas flow control valve  614  in order to control or modulate the flow rate of the gas into the first mixer  619 . 
     As can be seen in the aspect depicted in  FIG.  9   , a liquid conduit  660  can be coupled to a liquid source  630  via a liquid intake  632 . In various aspects, the liquid source  630  can include any or all of the properties of the liquids and liquid source described above with reference to  FIG.  8   . The liquid conduit  660  can extend from the liquid intake  632  to a liquid pump  634  and on to the first mixer  619 . In aspects, the liquid pump  632  can comprise an electric motor  629 , which in turn may be controlled or operated by a computing device via a variable frequency drive, as discussed above with reference to  FIG.  8   . In aspects, a recirculation conduit  661  can optionally be included to aid in controlling the pressure in the portion  636  of the liquid conduit  660  adapted to receive the pumped liquid from the liquid pump  634 . In such aspects, a recirculation liquid control valve  635  can permit or block the recirculation of the liquid from the portion  636  of the liquid conduit  660  and through the recirculation conduit  661 , which may be returned to a holding vessel  631 . 
     The liquid conduit  660  can include, in aspects, a liquid meter  638  and one or more valves, e.g., a needle valve  637   a  and a liquid flow control valve  637   b , positioned between the liquid pump  634  and the first mixer  619 . In the same or alternative aspects, the liquid conduit  660  can include a liquid check valve  639  to prevent backflow from the first mixer  619  into the liquid conduit  660 . 
     As can be seen in the aspect depicted in  FIG.  9   , a chemical additives conduit  641  can be coupled to a chemical additives source  640  and operable to provide one or more chemical additives to a mixture of the liquid and the gas downstream of the first mixer  619  in the mixture conduit  691 . In aspects, the chemical additives and the chemical additives source  640  can include any or all of the properties of the chemical additives and the chemical additives source discussed above with reference to  FIG.  8   . 
     In aspects, a chemical pump  642  can be coupled to the chemical additives conduit  641  in order to provide the flow of the chemical additives from the chemical additives source  640  to the second mixer  645 , where the chemical additives can be incorporated into the mixture of the liquid and the gas. In aspects, a chemical additives needle valve  644  or other valve can be positioned along the chemical additives conduit  641  between the chemical pump  642  and the second mixer  645  to control the flow of chemical additives into the mixture conduit  691  and ultimately through an outlet  621  and into a well  650 . 
     In the aspect depicted in  FIG.  9   , a skid  700 , or base member of a frame assembly, can support the conduits and components depicted in the interior portion  701  of the skid  700 . As depicted in  FIG.  9   , the chemical additives source  640 , the gas source  620 , the supplemental liquid source  631 , and the liquid source  630  are external to the interior portion  701  of the skid  700 . 
     As discussed above, in various aspects the systems and processes herein can utilize a computing device to identify various parameters, e.g., one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters discussed above, and tailor a flow rate of the liquid and gas mixture and/or tailor the compositional makeup of the mixture by controlling the flow rate of the liquid and/or the gas. For instance, as noted above, such a computing device can identify various parameters, e.g., one nor more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters and operate or direct the operation of one or more of the valves or pumps discussed above in order to control the flow rate or flow of the gas, the liquid, the chemical additives, or a combination thereof. 
     As discussed above, in various aspects, the systems and processes disclosed herein can be utilized to increase well production, for example, by injecting a mixture of a gas and a liquid into a well.  FIG.  10    depicts an example injection system  800  coupled to a well  900 . In various aspects, the injection system  800  of  FIG.  10    can include any or all of the parameters discussed above with respect to  FIGS.  5 A- 9   . It should be understood that while the well  900  depicted in  FIG.  10    is generally a vertically oriented well, the systems and processes disclosed herein can also be utilized on horizontal wells. That is in certain aspects, the injection systems disclosed herein can be coupled to a vertical or a horizontal well for injecting a liquid and gas mixture therein, e.g., to increase well production. 
     The well  900  and associated components, in aspects, can be similar to the well  100  and associated components discussed above with respect to  FIG.  1   . For example, as can be seen in  FIG.  10   , the well  900  includes a borehole  902  that extends into the ground to a formation (not depicted in the figures). In the aspect depicted in  FIG.  10   , the borehole  902  includes a production tubing  910  extending through at least a portion of the borehole  902  and is adapted to permit production fluids, including but not limited to crude oil, to be extracted from the formation. Further, as can be seen in  FIG.  10   , there is a annulus  920  that is the space between the exterior  912  of the production tubing  910  and the surface  922  of the borehole  902 . 
     In various aspects of the systems and processes described herein, the mixture of the liquid and the gas, can exit an outlet  820  of the injection system  800  and be injected into the annulus  920  via a conduit  830 . In such aspects, the mixture of the liquid and the gas may travel down the borehole  902  to a deep-set valve  930  coupled to the production tubing  910 , where the liquid and/or the gas is transported into the production tubing  910 , as indicated by the solid arrow extending down to the deep-set valve  930 . In an aspect not depicted in the figures, as discussed above, there may not be a valve at or near the bottom of the production tubing and the systems described herein can provide the mixture to the bottom of the production tubing where such mixture can enter the production tubing, as indicated by the dashed arrow extending down the annulus  920  and into the production tubing  910 . 
     It should be understood that while this one example operation depicted in  FIG.  10    describes the gas, liquid, or mixture thereof being injected from the injection system  800  and into the annulus  920  and ultimately into the production tubing  910  to facilitate increased extraction of production fluids by traveling through the production tubing  910  and out of the well  900 , an alternative operation is also contemplated by the systems and processes described herein. For instance, in one aspect, the gas, liquid, or mixture thereof can be injected from the injection system  800  and into the production tubing  910  and thereby travel downhole and enter the annulus  920  via a valve or bottom of the tubing to facilitate extraction of production fluids out and through the annulus  920 . 
     As discussed above, in various aspects, the systems and processes disclosed herein can include utilizing a liquid that comprises hydrocarbons in the mixture of the liquid and the gas. In such aspects, the systems disclosed herein can utilize a production fluid, e.g., a crude oil from the well, as the liquid source or liquid for use as at least one component of the liquid in the mixture of a liquid and a gas for injecting into the well.  FIG.  10    depicts one example arrangement where an injection system, e.g., the injection system  800 , is adapted to receive a production fluid as a liquid source. As can be seen in  FIG.  10   , a conduit  812  is coupled to a liquid inlet  810  and extends into the production tubing  910  so that the production fluid, for example a crude oil, can be utilized in the systems and processes disclosed herein. As depicted in  FIG.  10   , the production fluid may be exposed to one or more post-production systems or processes, e.g., the system  1000 , prior to transporting the crude oil or other fluid to the liquid inlet  810 . A non-limiting list of post-production systems and processes includes the use of one or more separators to remove water, other liquids, and/or gas, and the use of a storage vessel from which the crude oil can be withdrawn. 
     In various aspects as discussed above, the flow rate of the mixture exiting the outlet  820  and being injected into the annulus  920  can be tailored based on identifying one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. In such aspects, a computing device  840  can identify and/or receive information on one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters to determine the flow rate of the mixture of the liquid and the gas. The flow rate of the mixture of the liquid and the gas can be adjusted as discussed above with reference to  FIGS.  5 A- 9   . In such aspects and not depicted in the figures, one or more flow meters, pressure gauges, and/or temperature gauges may be placed at any specific location in the production tubing  910 , annulus  920 , borehole  902 , conduit  830 , and/or conduit  812 , and be adapted to transmit such information to the computing device  840  for use in tailoring the flow rate of the liquid and gas mixture. 
       FIG.  11    depicts a system  1100  for use in implementing aspects described herein for optimizing the injection of the liquid and gas mixture into a well and/or for tailoring the flow rates of the liquid and the gas into the well. It should be understood that the system  1100  is an example of one suitable computing system environment and is not intended to suggest any limitation as to the scope of use or functionality of aspects of the present invention. Neither should the system  1100  of  FIG.  11    be interpreted as having any dependency or requirement related to any single source module, service, or device illustrated therein. 
     Generally, the system  1100  can include an injection optimizer  1110  that can identify or receive a variety of inputs or information, such as one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, to tailor or optimize the relative amounts of the gas and liquid in the mixture being injected into a well and/or the flow rate of the mixture being injected into the well, e.g., to increase well production. In aspects, the system  1100  may include the injection optimizer  1110 , one or more sensors  1120 , one or more computing devices  1140 , one or more controllers  1150 , and optionally one or more data sources  1160 . In aspects, the injection optimizer  1110 , one or more sensors  1120 , one or more computing devices  1140 , one or more controllers  1150 , and one or more data sources  1160  may be in communication with each other, through wired or wireless connections, and/or through a network  1130 . The network  1130  may include, without limitation, one or more local area networks (LANs) and/or wide area networks (WANs). Such networking environments are commonplace in enterprise-wide computer networks, intranets, and the Internet. Accordingly, the network  1130  is not further described. 
     In one or more aspects, the one or more sensors  1120  can include any sensors that can identify or provide information related to one or more of the well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters discussed above. In such aspects, the one or more sensors  1120  can include any or all of the sensors, flow meters, pressure gauges, and temperature gauges utilized in an artificial lift system, including sensors associated with liquid and/or gas conduits and sensors in or near the well. In aspects, the one or more sensors  1120  can include any or all of the sensors, flow meters, or gauges discussed above with reference to  FIGS.  8  and  9    that are operable to measure flow rate, temperature, and/or pressure, of the liquid, gas, or mixture thereof. In the same or alternative aspects, the one or more sensors  1120  can include one or more pressure and/or temperature sensors downhole, e.g., a pressure sensor operably coupled to a downhole injection valve, e.g., the deep-set valve  930  discuss above with reference to  FIG.  10   . In further aspects, the one or more sensors  1120  can include one or more sensors associated with measuring various properties of the production fluid, tubing, casing head, or a combination thereof. 
     In certain aspects, the one or more data sources  1160  can include any information associated with the well, source gas, source liquid, or produced fluids. For instance, in one aspect, the one or more data sources  1160  can include information associated with the well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. For instance in aspects, the one or more data sources  1160  can include information associated with the well geometry, historical well production parameters, or produced fluid parameters. In one aspect, the one or more data sources  1160  can include prior parameter information, while the one or more sensors  1120  can include real-time or near real-time parameter information. 
     In aspects, the one or more controllers  1150  can include any device capable of adjusting a valve, pump, motor associated with a valve or pump, or the like for controlling the flow or flow rate of a liquid, gas, or a mixture thereof. In aspects, the one or more controllers  1150  can be associated with any of the flow control valves, electric motors, or pumps discussed above, such as the flow control valves, electric motors, or pumps described in the systems of  FIGS.  8  and  9   . 
     In various aspects, the injection optimizer  1110  can include a receiver  1112 , a flow rate determiner  1114 , and an output communicator  1116 . In aspects, the receiver  1112 , the flow rate determiner  1114 , and the output communicator  1116  may be implemented as one or more stand-alone applications. Further, various services and/or modules may be located on any number of servers. By way of example only, the injection optimizer  1110  may reside on a server, cluster of servers, a cloud-computing device or distributed computing architecture, or a computing device remote from one or more of the data sources  1160 , the one or more computing devices  1140 , or the one or more controllers  1150 . In certain aspects, one or more services or modules of the injection optimizer  1110  may reside in one or more of the one or more computing devices  1140  associated with the injection systems described herein. In the same or alternative aspects, one or more services and/or modules of the injection optimizer  1110  may reside in one or more servers, cluster of servers, cloud-computing devices or distributed computing architecture, or a computing device remote from the one or more computing devices  1140  associated with the artificial lift systems described herein. 
     In various aspects, the receiver  1112  of the injection optimizer  1110  can receive information from the one or more sensors  1120  and/or the one or more data sources  1160 . In certain aspects, the information from the one or more sensors  1120  and/or the one or more data sources  1160  may be transmitted to and received by the receiver  1112  via the network  1130  and may include wired or wireless transmission of the information, including but not limited to a physical USB connection, an Ethernet connection, a Bluetooth connection, near-field communication, WiFi communication, wireless USB communication, optical communication, such as IrDA, a cellular network or a combination thereof. In aspects, the one or more computing devices  1140  may transmit to the receiver  1112  data from the one or more data sources  1160  and/or the one or more sensors  1120 . 
     In aspects, once the injection optimizer  1110  has received the information from the one or more sensors  1120  and/or the one or more data sources  1160 , the flow rate determiner  1114  utilizes that information to determine a flow rate of the liquid and/or the gas in the mixture, and/or utilizes that information to determine the relative amounts of the liquid and the gas in the mixture. 
     In one example, as discussed above, the relative amounts of the gas and liquid in the mixture and/or the flow rate of the mixture can be determined by the flow rate determiner  1114 , based on one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters received by the receiver  1112 , in an effort to: increase well production, decrease the downhole pressure, decrease the density of the production fluid, or a combination thereof. Additionally or alternatively, in an example aspect, the relative amounts of the gas and liquid in the mixture and/or the flow rate of the mixture can be tailored or optimized based on one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters received by the receiver  1112 , in an effort to: increase well production, decrease the downhole pressure, decrease the density of the production fluid, or a combination thereof. 
     In another example also discussed above, once the injection optimizer  1110  has received the information, e.g., one or more of the well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, from the one or more sensors  1120  and/or the one or more data sources  1160 , the flow rate determiner  1114  can determine the liquid and/or gas injection or flow rates sufficient to facilitate downward bubble flow in the well. 
     It should be understood that the above examples are only a few scenarios to demonstrate the functionality of the flow rate determiner  1114  and that any combination of other information from the one or more data sources  1160  and/or the sensors  1120  can be utilized to optimize the flow rates of the liquid and/or the gas in the mixture for injecting into the well, and/or to determine the compositional parameters of the liquid and the gas in the mixture. 
     In aspects, the output communicator  1116  communicates to the one or more controllers  1150  and/or the one or more computing devices  1140  the determined flow rates for the liquid and/or the gas in the liquid and gas mixture. For instance in one aspect, the output communicator  1116  can communicate with the one or more controllers  1150  to adjust the flow rate of the liquid, the gas or the liquid and the gas. As noted above, the one or more controllers  1150  can be associated with any of the flow control valves, electric motors, or pumps discussed above. In one aspect, the output communicator  1116  can communicate the determined flow rates for the liquid and/or the gas in the liquid and gas mixture to the one or more computing devices  1140 , where the one or more computing devices  1140 , in turn, can directly or indirectly communicate the determined flow rates, or operations or instructions that achieve the determined flow rates, to components that control the one or more valves, electric motors, or pumps. For instance in one example, the one or more computing devices  1140  can provide instructions to control the amount of power going to an electric motor that controls one or more of a liquid pump, a flow control valve, or a pump. 
       FIG.  12    depicts one example operating environment for a computing device in which aspects of the present disclosure may be implemented is described below in order to provide a general context for various aspects of the present disclosure. Referring to  FIG.  12   , an example operating environment for implementing aspects of the present disclosure is shown and designated generally as computing device  1200 . The computing device  1200  is but one example of a suitable computing environment and is not intended to suggest any limitation as to the scope of use or functionality of aspects disclosed herein. Neither should the computing device  1200  be interpreted as having any dependency or requirement relating to any one component nor any combination of components illustrated. 
     Aspects herein may be described in the general context of computer code or machine-useable instructions, including computer-useable or computer-executable instructions such as program modules, being executed by a computer or other machine, such as a personal computing device. Generally, program modules including routines, programs, objects, components, data structures, and the like, and/or refer to code that performs particular tasks or implements particular abstract data types. Aspects disclosed herein may be practiced in a variety of system configurations, including hand-held devices, consumer electronics, general-purpose computers, more specialty computing devices, and the like. Aspects disclosed herein may also be practiced in distributed computing environments where tasks are performed by remote-processing devices that are linked through a communications network. 
     With continued reference to  FIG.  12   , the computing device  1200  includes a bus  1210  that directly or indirectly couples the following devices: a memory  1212 , one or more processors  1214 , one or more optional presentation components  1216 , one or more input/output (I/O) ports  1218 , one or more I/O components  1220 , and an illustrative power supply  1222 . The bus  1210  represents what may be one or more busses (such as an address bus, data bus, or combination thereof). Although the various blocks of  FIG.  12    are shown with lines for the sake of clarity, in reality, these blocks represent logical, not necessarily actual, components. For example, one may consider a presentation component such as a display device to be an I/O component. Also, processors have memory. It is appreciated that such is the nature of the art, and reiterate that the diagram of  FIG.  12    is merely illustrative of an exemplary computing device that can be used in connection with one or more embodiments of the present invention. Distinction is not made between such categories as “workstation,” “server,” “laptop,” “hand-held device,” etc., as all are contemplated within the scope of  FIG.  12    and reference to “computing device.” 
     The computing device  1200  typically includes a variety of computer-readable media. Computer-readable media may be any available media that can be accessed by the computing device  1200  and includes both volatile and nonvolatile media, removable and non-removable media implemented in any method or technology for storage of information such as computer-readable instructions, data structures, program modules or other data. Computer-readable media includes, but is not limited to, RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other optical disk storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium which can be used to store the desired information and which can be accessed by the computing device  1200 . Combinations of any of the above are also included within the scope of computer-readable media. 
     The memory  1212  includes computer-storage media in the form of volatile and/or nonvolatile memory. The memory may be removable, non-removable, or a combination thereof. Exemplary hardware devices include solid-state memory, hard drives, optical-disc drives, and the like. The computing device  1200  includes one or more processors that read data from various entities such as the memory  1212  or the I/O components  1220 . The optional presentation component(s)  1216  present data indications to a user or other device. Exemplary presentation components include a display device, speaker, printing component, vibrating component, and the like. 
     The I/O ports  1218  allow the computing device  1200  to be logically coupled to other devices including the I/O components  1220 , some of which may be built in. Illustrative components include a microphone, joystick, game pad, satellite dish, scanner, printer, wireless device, and the like. 
       FIG.  13    depicts a flow diagram illustrating a method  1300  for increasing well production while a well is currently producing a production fluid. At step  1310 , the method  1300  includes identifying one or more parameters. In aspects, the one or more parameters can include any or all of the parameters discussed above with reference to the injection processes and systems. For instance in one aspect, the one or more parameters can include one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. In aspects, the one or more parameters can be provided by or received from the one or more sensors  1120  and/or the one or more data sources  1160  discussed above with reference to the system  1100  of  FIG.  11   . 
     At step  1320 , the method  1300  includes determining a first flow rate of a liquid, a gas, or a liquid and gas mixture. In aspects, the step  1320  can include determining a first flow rate of a liquid, a gas, or a liquid and gas mixture based on the one or more parameters identified in step  1310 . For instance, in such an aspect, the first flow rate of the liquid, gas, or liquid and gas mixture can be tailored based on the identifying of step  1310  for injecting into a well to: increase well production, decrease the downhole pressure, decrease the density of the production fluid, or a combination thereof. In the same or alternative aspects, the flow rate of the liquid, gas, or liquid and gas mixture can be tailored based on the identifying of step  1310  to facilitate downward gas bubble flow in the well. In aspects, determining a flow rate of a liquid, a gas, or a liquid and gas mixture based on the one or more parameters identified in step  1310  can include the use of the injection optimizer  1110  discussed above with reference to the system  1100  of  FIG.  11   . In aspects not depicted in the figures, the method  1300  can also include subsequent to determining a flow rate of the liquid, identifying one or more second parameters, such as one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. In aspects, the one or more second parameters can be provided by or received from the one or more sensors  1120  and/or the one or more data sources  1160  discussed above with reference to the system  1100  of  FIG.  11   . In further aspects, based on the one or more second parameters, the method  1300  can include determining a second flow rate of the liquid and gas mixture that is different than the first flow rate, in order to increase well production relative to that achieved with the injection of the liquid and gas mixture at the first flow rate. In one aspect, the second flow rate of the liquid and gas mixture can include a decreased amount of liquid in the mixture and/or an increased amount of gas in the mixture. 
     ADDITIONAL EMBODIMENTS 
     Embodiment 1. A method for injection of a liquid and a gas mixture into a well that is producing a production fluid at a first production rate, wherein the well comprises a borehole extending into the ground to a formation, the borehole having at least one production tubing extending through at least a portion of the borehole, the method comprising: injecting a first mixture of a liquid and a gas into the well while the well is producing the production fluid at the first production rate, wherein the first mixture is injected at a first flow rate to cause the well to increase production of the production fluid to a second production rate that is greater than the first production rate. 
     Embodiment 2. The method according to embodiment 1, wherein the liquid of the first mixture comprises liquid hydrocarbons. 
     Embodiment 3. The method according to embodiment 1 or 2, wherein the hydrocarbons comprise crude oil. 
     Embodiment 4. The method according to embodiment 3, wherein the crude oil was produced from the well. 
     Embodiment 5. The method according to any of embodiments 1-4, wherein the gas comprises methane. 
     Embodiment 6. The method according to any of embodiments 1-5, wherein the gas is present in the mixture in an amount of from 10% by volume of the mixture to 99% by volume of the mixture. 
     Embodiment 7. The method according to any of embodiments 1-6, further comprising, prior to the injecting the first mixture of the liquid and the gas into the well, forming the first mixture at a location proximal to the well. 
     Embodiment 8. The method according to any of embodiments 1-7, further comprising, prior to the injecting the first mixture of the liquid and the gas into the well, determining the first flow rate based on one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. 
     Embodiment 9. The method according to embodiment 8, wherein the well geometry parameters comprise one or more of: an internal diameter of well tubing, an external diameter of well tubing, an internal diameter of a casing string, a depth of the casing string, an inclination of the casing string, a diameter of the vertical wellbore section, a depth of the vertical section, or a depth of an injection valve; wherein the produced fluids properties comprise one or more of: a density of the well-produced fluids, an API gravity of the produced fluids, such as an API gravity of the oil or condensate, a viscosity of the well-produced fluids, a pressure of the well-produced fluids, a volume of the well-produced fluids, or a temperature of the well-produced fluids; wherein the well productivity parameters comprises one or more of: an average reservoir pressure, a flow potential for the well, production rates from the well, an average oil or condensate rate, an average water rate (barrels per day), an average gas rate, a flowing tubing pressure, a wellhead pressure, a choke setting, a well head flowing temperature; and wherein the surface production parameters comprise one or more of: a gas conduit pressure, a liquid conduit pressure, a liquid and gas mixture conduit pressure, an outlet pressure, a well head shut-in pressure, a well head shut-in temperature, a production line pressure, a separator pressure, a casing head shut-in temperature, a casing head shut-in pressure, the gas volume available or extractable from the gas source, or source gas pressure. 
     Embodiment 10. The method according to any of embodiments 1-9, further comprising, subsequent to the injecting the first mixture of the liquid and the gas into the well, identifying one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. 
     Embodiment 11. The method according to embodiment 10, further comprising, subsequent to the identifying one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, injecting a second mixture of a liquid and a gas into the well, wherein the second mixture is different than the first mixture. 
     Embodiment 12. The method according to any of embodiments 1-11, wherein, prior to the injecting the first mixture of the liquid and the gas into the well, the at least one production tubing comprises a first volume of production fluid therein having a first density, and wherein, subsequent to the injecting the first mixture of the liquid and the gas into the well, the at least one production tubing comprises a second volume of production fluid therein having a second density, the second density being less than the first density. 
     Embodiment 13. A method for injection of a liquid and gas mixture into a producing well, wherein the well comprises a borehole extending into the ground to a formation, the borehole having at least one production tubing extending through at least a portion of the borehole, the method comprising: injecting a first mixture of a liquid and a gas into the well while the well is producing a first volume of production fluid, the first volume of production fluid having a first density, wherein the first mixture is injected at a first flow rate thereby resulting in the formation of a second volume of production fluid, the second volume of production fluid having a second density that is less than the first density. 
     Embodiment 14. The method according to embodiment 13, wherein the liquid of the first mixture comprises liquid hydrocarbons. 
     Embodiment 15. The method according to embodiment 14, wherein the hydrocarbons were produced from the well. 
     Embodiment 16. The method according to any of embodiments 13-15, wherein the gas comprises methane. 
     Embodiment 17. The method according to any of embodiments 13-16, wherein the gas is present in the mixture in an amount of from 10% by volume of the mixture to 99% by volume of the mixture. 
     Embodiment 18. The method according to any of embodiments 13-17, further comprising, prior to the injecting the first mixture of the liquid and the gas into the well, determining the first flow rate based on one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. 
     Embodiment 19. The method according to any of embodiments 13-18, further comprising, prior to the injecting the first mixture of the liquid and the gas into the well, determining a relative amount of the liquid and a relative amount of the gas in the first mixture, based on one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. 
     Embodiment 20. The method according to embodiments 18 or 19, wherein the well geometry parameters comprise one or more of: an internal diameter of well tubing, an external diameter of well tubing, an internal diameter of a casing string, a depth of the casing string, an inclination of the casing string, a diameter of the vertical wellbore section, a depth of the vertical section, or a depth of an injection valve; wherein the produced fluids properties comprise one or more of: a density of the well-produced fluids, an API gravity of the produced fluids, such as an API gravity of the oil or condensate, a viscosity of the well-produced fluids, a pressure of the well-produced fluids, a volume of the well-produced fluids, or a temperature of the well-produced fluids; wherein the well productivity parameters comprises one or more of: an average reservoir pressure, a flow potential for the well, production rates from the well, an average oil or condensate rate, an average water rate (barrels per day), an average gas rate, a flowing tubing pressure, a wellhead pressure, a choke setting, a well head flowing temperature; and wherein the surface production parameters comprise one or more of: a gas conduit pressure, a liquid conduit pressure, a liquid and gas mixture conduit pressure, an outlet pressure, a well head shut-in pressure, a well head shut-in temperature, a production line pressure, a separator pressure, a casing head shut-in temperature, a casing head shut-in pressure, the gas volume available or extractable from the gas source, or source gas pressure. 
     Embodiment 21. A computing device having at least one processor and computer-readable instructions stored thereon, the computer-readable instructions, when executed by the at least one processor cause the computing device to: identify one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters; and based on the identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, determine a first flow rate of a liquid, a gas, or a liquid and gas mixture, for injecting into a well to increase well production of a production fluid. 
     Embodiment 22. One or more nontransitory computer storage media storing computer-useable instructions that, when used by one or more computing devices, cause the one or more computing devices to perform operations comprising: identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters; and based on the identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, determining a first flow rate of a liquid, a gas, or a liquid and gas mixture, for injecting into a well to increase well production of a production fluid. 
     Although the present invention has been described in terms of specific embodiments, it is not so limited. Suitable alterations/modifications for operation under specific conditions should be apparent to those skilled in the art. It is therefore intended that the following claims be interpreted as covering all such alterations/modifications as fall within the true spirit/scope of the invention.