Abstract:
Implementations described and claimed herein provide a method of treating a subterranean formation penetrated by a wellbore. The method includes introducing a composition comprising a gas into fractures of the subterranean formation extending from the wellbore, followed by or simultaneously with introducing a carrier fluid into the subterranean formation under sufficient pressure to fracture a portion of the subterranean formation and release hydrocarbons from the subterranean formation, wherein the gas occupies the fractures at a sufficient pressure to cause the carrier fluid to be diverted to additional fractures of the subterranean formation defined by the portion.

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
       [0001]    The present application claims priority under 35 U.S.C. §119 to U.S. Provisional Patent Application 62/145,439, which was filed Apr. 9, 2015, entitled “GAS DIVERTER FOR WELL AND RESERVOIR STIMULATION,” and is hereby incorporated by reference in its entirety into the present application. 
     
    
     TECHNICAL FIELD 
       [0002]    Aspects of the presently disclosed technology relate to diverter systems and in particular involve gas diverter systems. 
       BACKGROUND 
       [0003]    Oil and gas wells are stimulated and re-stimulated in various ways to increase production of a flow of hydrocarbons from a completed well. With a newly completed well with a large reservoir and easily captured hydrocarbons, for example, the well may not require much or any stimulation techniques to produce an adequate flow of hydrocarbons from the well. Other wells, depending on composition or otherwise, may require more well stimulation to release the hydrocarbons from the subterranean formation containing the hydrocarbons. 
         [0004]    In recent years, hydraulic fracturing has become a widely-used well stimulation technique to increase well production and access previously uncaptured hydrocarbons. Hydraulic fracturing involves hydraulically fracturing the subterranean formation with a pressurized liquid or carrier liquid, containing water, proppant (e.g., sand or man-made alternative), and/or chemicals, that is injected into a wellbore. Upon pressurizing the wellbore with the carrier liquid, the formation fractures or cracks and the carrier fluid can leave behind proppant, which allows the hydrocarbons to flow more freely through the fractures and into the wellbore to be recovered. In some instances, a downhole electric submersible pump may pump the hydrocarbons from the reservoir to overcome the hydrostatic head pressure of the hydrocarbons, or the hydrocarbons may flow freely up the wellbore without assistance. 
         [0005]    As seen in  FIG. 1 , which is a side view of a horizontal drilling operation  100  utilizing hydraulic fracturing, a pressurized liquid  102  may cause multiple fractures  104  within the subterranean formation  106 . Fractures  104  formed by the pressurized liquid  102  can be of varying sizes. Accordingly, larger fractures or pore volumes  108  may cause a lower stress zone  110  within the formation such that upon stimulation and re-stimulation of the well the carrier liquid  102  tends to concentrate in these lower stress zones  110 . These lower stress zones  110  can be caused by hydrocarbon depletion, lower pore pressure, and/or higher permeability of the reservoir  106 . Permeability of the reservoir can, in part, depend on the extensiveness of fractures and/or pores, and the interconnectivity of the fractures and/or pores that create pathways for hydrocarbons to flow. As a result of the lower stress zones, the hydrocarbons are more likely to flow through these larger fractures or pore volumes  108 , and/or those with interconnectivity, until depletion. The fractures and/or pore volumes  104  of finer sizes  112  and/or those lacking interconnectivity tend to be concentrated in higher stress zones  114  such that the carrier liquid  102  is less likely to effectively hydraulically fracture those higher stress zones and thus influence the flow of hyrdrocarbons in these regions upon stimulation or re-stimulation. This is in part, because the pressure of the carrier liquid  102  is generally evenly distributed along the wellbore in the treated area such that the carrier liquid  102  remains concentrated in the lower stress zones  110  rather than the higher stress zones  114 . The higher stress zones  114 , in contrast to the lower stress zones  110 , can be caused by higher pore pressure, ineffective hydraulically fractured regions, lower permeability of the reservoir  106 , or generally less depleted portions of the reservoir  106 . As such, the carrier liquid  102  tends to not affect the higher stress zones  114 , which may contain hydrocarbons, unless additional systems and methods are employed. 
         [0006]    In subsequent well treatments or in initial well treatments, diverter systems may be used to divert the carrier liquid  102  from the lower stress zones  110 , which may be depleted from previous treatments, to the previously un-accessed, higher stress zones  114 . Diverting the carrier liquid  102  into these higher stress zones  114  may be difficult over large areas of the wellbore and reservoir for a number of reasons. In new wells, the difficulty may be due to differences in stresses from different lithologies or from different reservoir characteristics along the well. Differences in stress can be due to natural in-situ stress conditions or man-made activities such as well stimulation or depletion of fluids. In previously stimulated wells, the difficulty may be due to adequately blocking the fractures and/or pore volume  108  in the lower stress zones  110  such that the carrier liquid  102  pressurizes the fractures  112  of the higher stress zones  114 . Diverter systems include the use of particulates (e.g., polymers) and chemical diverters within the carrier liquid  102 , among other methods, to block either the wellbore or the formation near the wellbore so that a portion of the carrier liquid  102  may be diverted to the fractures  112  in the higher stress zones  114  and also create new fractures in the higher stress zones. 
       SUMMARY 
       [0007]    Aspects of the present disclosure involve a method of treating a subterranean formation penetrated by a wellbore. The method includes introducing a composition including a gas into features of the subterranean formation extending from the wellbore. The features including fractures or pore volumes. This step is followed by introducing a carrier fluid into the subterranean formation under sufficient pressure to fracture a portion of the subterranean formation and release hydrocarbons from the subterranean formation. The gas may occupy the features at a sufficient pressure to cause the carrier fluid to be diverted to additional features of the subterranean formation defined by the portion. The additional features may include additional fractures or pore volumes. 
         [0008]    Aspects of the present disclosure may also involve a method of treating a subterranean formation penetrated by a wellbore. The method includes introducing a diverting composition consisting of a gas into a wellbore and into fractures or pore volumes of the subterranean formation extending from the wellbore and introducing a carrier fluid into the subterranean formation, the gas being sufficiently pressurized within the fractures or pore volumes to cause the carrier fluid to pressurize additional fractures or pore volumes within the subterranean formation. 
         [0009]    Aspects of the present disclosure may also involve a method of treating a subterranean formation penetrated by a wellbore. The method includes introducing a diverting composition including a foam mixture of gas and liquid into features of the subterranean formation extending from the wellbore. The features may include fractures or pore volumes. The method may additionally include introducing a carrier fluid into the subterranean formation under sufficient pressure to fracture a portion of the subterranean formation and release hydrocarbons from the subterranean formation. The foam mixture may occupy the features at a sufficient pressure to cause the carrier fluid to be diverted to additional features of the subterranean formation defined by the portion. The additional features may include additional fractures or pore volumes. 
         [0010]    Aspects of the present disclosure may also involve a method of treating a subterranean formation penetrated by a wellbore. The method may include introducing a composition including a substantially compressible substance into features of the subterranean formation extending from the wellbore. The features may include fractures or pore volumes. The method may additionally include introducing a substantially incompressible substance into the subterranean formation under sufficient pressure to fracture a portion of the subterranean formation and release hydrocarbons from the subterranean formation. The substantially compressible substance may occupy the features at a sufficient pressure to cause the substantially incompressible substance to be diverted to additional features of the subterranean formation defined by the portion. The additional features may include additional fractures and pore volumes. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0011]      FIG. 1  is a side view of a hydraulic fracturing operation showing high and low stress zones. 
           [0012]      FIG. 2  is a side view of a horizontal drilling operation utilizing the diversion technique described herein where a gas is introduced into the well. 
           [0013]      FIG. 3  is a side view of the horizontal drilling operation utilizing the diversion technique described herein where a carrier liquid is introduced into the well. 
           [0014]      FIG. 4  is a flowchart illustrating the steps in utilizing the diversion technique described herein. 
           [0015]      FIG. 5  is a flowchart illustrating another set of steps in utilizing the diversion technique described herein. 
           [0016]      FIG. 6  is a flowchart illustrating yet another set of steps in utilizing the diversion technique described herein. 
       
    
    
     DETAILED DESCRIPTION 
       [0017]    Aspects of the presently disclosed technology involve a diversion technique for use in vertical, deviated, or horizontal wells undergoing a stimulation process (e.g., initial stimulation or re-stimulation) to divert a carrier liquid from treating previously stimulated areas (i.e., lower stress zones of the formation) and to force the carrier liquid to treat previously unstimulated areas (i.e., higher stress zones of the formation). The methods disclosed provide cost-effective means for improving the well production. After a wellbore is drilled and completed, stimulation operations are usually performed to enhance hydrocarbon (e.g. gas, oil, etc.) production into the wellbore and to enhance extraction of the hydrocarbons from the subterranean formation. Current diversion techniques use liquid or solid forms, such as chemical solutions (e.g., a borate solution) or, particulates (e.g., polymers spheres), which can be costly and potentially ineffective in diverting fluid to the higher stress regions/zones of the reservoir. Additionally, liquid-and solid-form diverters can be problematic as they leave residue that can damage the subterranean formation and can lead to inhibited production from the well. In contrast, the methods of the present disclosure are cost effective, operationally feasible based on current equipment available to the industry, and can enhance the rate of extraction of the hydrocarbons. In particular, the use of a gas as the diversion medium allows for greater filling of the reservoir in lower stress zones such that a carrier liquid can be more efficiently diverted to the higher stress zones of the reservoir. The use of a gas as the diversion medium also has advantages in that no residue remains and the gas can be recovered during flowback. In certain instances, the gas may be recovered during flowback can be reused, recycled, or marketed. 
         [0018]    More particularly, and as seen in  FIG. 2 , which is a side view of a horizontal drilling operation  100  utilizing the diversion technique described herein, a first step in the diversion technique includes injecting a gas  116  into a wellbore  118  of a well  120  to pressurize the fractures  108  in the lower stress zones  110  of the subterranean formation  106  and the reservoir. In certain implementations, the gas  116  may be in a liquid phase, a gas phase, or a foam mixture of gas and a liquid. The gas is introduced to infiltrate the formation  106  and the reservoir holding the hydrocarbons. The gas can travel through a stimulation network of fractures and/or pore volumes (i.e., man-made or naturally occurring). Upon infiltration, the gas will occupy pore volumes and existing fractures in the formation  106 . In some instances, the pore volume can be preexisting from the natural formation or areas/regions of hydrocarbon depletion. This gas infiltration creates a barrier for a carrier liquid  102  that is subsequently delivered into the wellbore and diverted to the higher stress zones  114 . The gas in the stimulation network can build a sufficient pressure in the network allowing subsequently delivered carrier fluid or liquid to be diverted into previously untreated areas of the formation. In some instances, this method will allow for the diversion of a fluid or liquid to a portion of the formation that is a significant distance from the wellbore (i.e. far-field). 
         [0019]    The subterranean formation may include one or more of any type of rocks, such as sedimentary rocks like sandstone, limestone, and shale; igneous rocks like granite and andesite; or metamorphic rocks like gneiss, slate, marble, schist, and quartzite. In certain implementations, the subterranean formation may be a shale formation, a clay formation, a sandstone formation, a limestone formation, a carbonate formation, a granite formation, a marble formation, a coal bed, or combinations thereof. 
         [0020]    As seen in  FIG. 3 , which is a side view of the horizontal drilling operation  100  utilizing the diversion techniques described herein, a second step in the diversion technique includes injecting the carrier liquid  102  into the wellbore  118  such that the carrier liquid  102  pressurizes and fractures additional fractures  112  of the formation  106  that were previously not stimulated. Without injecting the gas  116  into the wellbore, the carrier liquid  102  would not be diverted to untreated areas and would otherwise infiltrate the fractures  108  of the lower stress zone  110 . Sufficiently pressurizing the fractures  108  in the lower stress zone  110  causes the subsequently injected carrier liquid  102  to bypass the gas-filled, pressurized fractures  108  in the lower stress zones  100  and can be directed to infiltrating the fractures  112  of the high stress zone  114  or create new fractures. 
         [0021]    The gas  116  may be delivered through a wellhead  126  of the well  120 . In some embodiments, the gas  116  may be delivered via a storage truck  122  positioned on the ground  124  near the wellhead  126 . In other embodiments, the gas  116  may be delivered via pipeline, a storage tank, other gas producing wells, or other suitable supply sources. 
         [0022]    Factors effecting the volume of gas  116  to be introduced in the well  120  include the size of the depleted regions of the reservoir (including pore volume and fractures), leak off rate of the gas  116 , and the extent of existing fracture and reservoir conditions (e.g. reservoir pressure—if the pressure is high it will compress the gas or foam requiring more volume to occupy the fractures/pore volumes). 
         [0023]    For instance, in some embodiments, the volume of the gas can range from about 1000 standard cubic feet (scf) to about 100,000,000 scf or greater. In various embodiments, the gas can be injected at rates within a range of about 30 scf/min to about 500,000 scf/min. In some embodiments, the gas can be injected at a rate of about 10,000 to about 20,000 scf/min. 
         [0024]    In certain instances, the gas  116  may be injected into the well over an extended period of time. For example, the gas  116  may be injected over a period of time that can be minutes, hours, days, or months, depending on a number of factors. In some embodiments, the gas  116  may be injected over a period of time of at least 2 hrs. In other embodiments, the gas  116  may be injected over a period of time of at least a day. For example, in certain instances, the gas  116  may be injected into the well from a neighboring natural gas well, for example. A worker may check the pressure at a subsequent time (e.g., days later) and determine that, in order to meet a desired pressure within the wellbore, additional gas  116  may need to be injected into the wellbore and continue the injection of the gas. A subsequent check of the pressure (e.g., days later), may indicate that the pressure is sufficient for the introduction of the carrier liquid  102 . Thus, in this example, it is possible for weeks to go by with intermittent addition of gas  116  into the well before a sufficient pressure is reached to begin introduction of the carrier liquid  102 . 
         [0025]    The gas  116  may include any number of gasses and may include nitrogen, hydrogen, methane, ethane, propane, butane, carbon dioxide, any inert gas, or any combinations thereof. The gas  116  may be deployed into the well  120  in a number of ways and in various phases. In certain implementations, the gas  116  may be in a gas phase and pumped directly into the wellbore  118  from the wellhead  126 . In other implementations, the gas  116  may be in a liquid phase above ground  124 , and the gas  116  is heated sufficiently at the surface for the gas  116  to enter the gas phase as it is being introduced into the wellbore  118 ,thereby being in the gas phase when it infiltrates the pore volumes and/or fractures. In yet other implementations, the gas may be in a liquid phase when it is introduced to the wellbore. The gas in the liquid phase may be pumped into the well and allowed to remain in the well  120  for a sufficient amount of time such that the reservoir temperature causes the liquid phase gas  116  to change phases from a liquid to a gas and infiltrate the fractures and pore volumes  108 . For example, the reservoir temperature may range from 120 degrees Fahrenheit (F) to greater than 600 degrees F. The gas 116 in a liquid phase may be pumped into the well at a lower temperature (e.g., −69° F. to 80 ° F.), and through heat exchange from the higher temperature of the well, can transition from the liquid phase to a gas phase. 
         [0026]    In certain implementations, a foam mixture of liquid and gas may be pumped into the well  120 , instead of gas  116 . The foam may be delivered through a wellhead of the well. In some embodiments, the foam may be delivered via a storage truck  122  positioned on the ground  124  near the wellhead  126 . In other embodiments, the gas  116  may be delivered via pipeline, a storage tank, or other suitable supply sources. 
         [0027]    Foam quality is conventionally defined as the volume percent gas within foam at a specified pressure and temperature. In certain instances, the quality of the foam may be at least 30. That is, there is at least 30% gas in the foam and the balance is liquid. In certain instances, the quality of the foam may be at least 40. That is, there is at least 40% gas in the foam and the balance is liquid. In certain instances, the quality of the foam may be at least 50. That is, there is at least 50% gas in the foam and the balance is liquid. In certain instances, the quality of the foam may be at least 60. That is, there is at least 60% gas in the foam and the balance is liquid. In certain instances, the quality of the foam may be greater than 70. In certain instances, the quality of the foam may be greater than 80. In certain instances, the quality of the foam may be greater than 90. 
         [0028]    A first step in the diversion technique includes injecting a gas  116  into a wellbore  118  of a well  120  to pressurize the fractures and/or pore volumes  108  in the lower stress zones  110  of the subterranean formation  106  and the reservoir. The gas  116  is introduced to infiltrate the formation  106  and the reservoir holding the hydrocarbons. The gas  116  can travel through a stimulation network of fractures and/or pore volume (manmade or naturally occurring) extending from the wellbore  118 . Upon infiltration, the gas  116  will occupy pore volumes and existing fractures in the formation  106 . In some instances, the pore volume and fractures  108  can be preexisting from the natural formation or areas/regions of hydrocarbon depletion. This gas  116  infiltration creates a barrier for a carrier liquid  102  that is subsequently delivered into the wellbore  118  and diverted to the higher stress zones  114 . The gas  116  in the stimulation network will build a sufficient pressure, allowing subsequently delivered carrier fluid or liquid  102  to be diverted into previously untreated areas of the formation. 
         [0029]    In all implementations, the gas  116  or foam may infiltrate the fractures and pore volumes of the formation beyond the wellbore of the well  120  to a distance that is substantial or far-field from the wellbore, outside of a perforation tunnel, or outside of a formation face in open hole. The gas or foam  116  can infiltrate the fractures and/or pore volumes extending through the length of the well and throughout the reservoir, including far-field areas. This is an advantage of the gas and foam  116  that typical chemical and particulate diverter systems do not have. As an example, in certain implementations, far-field areas of the formation may be about 10 feet to about 3000 feet from a wellbore or perforation tunnel. In other implementations, far-field areas of the formation may be about 100 feet to about 5,000 feet from a wellbore or perforation tunnel. 
         [0030]    As illustrated in  FIG. 3 , the carrier liquid  102  may be delivered through the wellhead  126 . In some embodiments, the carrier liquid  102  may be delivered to the well  120  via a storage truck  126  positioned on the ground  124  near the well head  126 . In certain implementations, the carrier liquid  102  or an amount of water used in the carrier liquid  102  may be supplied by storage tanks, naturally formed features (e.g., spring), a pipeline, etc. 
         [0031]    The carrier liquid  102  may be: slick-water, which is a water-based fluid and proppant combination of a low viscosity; a gel (e.g., borate, HPG, CMHPG, CMC); or a foam (e.g., nitrogen and water with gel, carbon dioxide, propane, and combinations thereof), among other carrier liquids. 
         [0032]    In the implementations described herein, the gas  116  may be substantially compressible within the wellbore and the reservoir, whereas the carrier liquid  102  may be substantially incompressible. The gas  116 , as compared with the carrier liquid  102 , tends to more easily fill the fractures and pore volumes because of its compressible nature, has a high relative permeability to the reservoir, and has a lower coefficient of friction, which allows it to fill the fractures and pore volumes that may not otherwise be penetrated by the carrier liquid  102 . The carrier liquid  102 , on the other hand, can more readily, as compared with the gas  116 , fracture the formation of the reservoir, in part, because it is substantially incompressible. 
         [0033]    In operation, as seen in the flow chart of  FIG. 4 , a first step  200  in the method is injecting the gas or foam  116  into the well  120  and reservoir. As stated previously, the gas or foam  116  is configured to pressurize the fractures and pore volumes  108  in the low stress zone  110 . This step  200  may include initially introducing the gas  116  into the well  120  by, for example, signaling the storage truck, tanker, or pipeline, among supply sources,  122  containing the gas  116  to begin pumping the gas  116  into the well  120  via the wellhead  126 . Also included in this step  200  may be the halting the flow of gas  116  into the well  120  by, for example, signaling the storage truck  122  to stop the flow of gas  116 . In other embodiments, the flow of the gas  116  can be monitored and controlled via a control system that may include pressure sensors, gauges or switches. 
         [0034]    In some embodiments, step  200  can comprise injection of gas using a continuous flow until the desired volume has been injected. In other embodiments, step  200  can comprise injecting the gas intermittently, in which the flow of the gas can be started, stopped, and started again, and stopped again in succession. In such embodiments, the flow of gas can be started and stopped any number of times until the desired volume has been injected. 
         [0035]    . As stated previously, this step  200  may take place over a period of minutes, hours, days, or weeks depending on the well and the type and availability of the diverting agent. In certain instances, the step  200  of injecting the well  120  with gas or foam  116  may take a period of hours until a desired pressure is reached within the well  120 . Alternatively, in other implementations, gas or foam  116  may be injected into the well  120  and it may take a period of weeks for sufficient pressure to be reached in the well  120  to begin injecting the carrier liquid  102 . And, over the period of weeks, gas or foam  116  may be added continuously, intermittently, or otherwise. 
         [0036]    Next, step  210  includes allowing the gas or foam  116  to remain in the well  120  and reservoir for a chosen dwell time, if appropriate, given the chosen deployment method. For example, with certain deployment methods, the gas or foam  116  may be required to remain in the well  120  and reservoir for a period of time before the carrier liquid  102  can be injected into the well  120 . For example, if the gas  116  is in a gas phase, there may not be a dwell time. That is, the carrier liquid  220  may be injected immediately upon halting of the flow of gas  116  into the well  120 . If the gas  116  is in the liquid phase and the gas will be heated into the gas phase by the heat/energy from the well  120  and reservoir, for example, the gas or foam  116  may need to remain in the well  120  for a dwell time of about 5 minutes to about 24 hours. In certain instances, the dwell time may be longer or shorter. In some embodiments, the dwell time can be less than twenty-four hours. In some embodiments, the dwell time can be less than one hour. In some embodiments, the dwell time can be less than thirty minutes. In other embodiments, the dwell time can be more than twenty four hours Continuing on, the next step  220  in the method is injecting the carrier liquid  102  into the well  120  and reservoir. This step  220  may include initially introducing the carrier liquid  102  into the well  120  by, for example, signaling the storage truck or other supply source  126  containing the carrier liquid  102  to begin pumping the carrier liquid  102  into the well  120  via the wellhead  126 . Also included in this step  220  may be halting the flow of carrier liquid  102  into the well  120  by, for example, signaling the storage truck, or supply source  122  to stop the flow of carrier liquid  102 . Carrier liquid  102  can be injected at rates of about 2 barrels/minute (bbl/min.) (84 gallons/min.) to greater than 200 bbl/min. (8400 gallons/min). 
         [0037]    The next step  230  asks if the previous operations will be repeated. If the well  120  requires additional treatment, for example, to divert the flow of carrier liquid  102  from additional low stress zones  110  that were formed from the previous operations to newer high stress zones  114  for fracturing. Criteria indicating the need for a re-treatment may, for example, be if the carrier liquid  102  experiences a high pressure, which may indicate the presence of a higher stress zone that may potentially fracture. On the other hand, lower pressure in the well  120  may indicate the carrier fluid  102  is infiltrating lower stress zones. In this situation, the operations may be repeated or ended depending on the particulars of the situation. If the operation is to be repeated, gas  116  may be re-injected into the well  120  and reservoir for additional treatment as described previously with respect to step  200  of the method. The entire cycle of steps  200 ,  210 , and  220  may be repeated any number of times until the end of treatment, at step  240 . The methods as described herein can be used to stimulate or treat vertical, deviated, or horizontal wells. 
         [0038]    Reference is now made to the flowchart of  FIG. 5 . As seen in the figure, a first step  300  of the method includes injecting the gas or foam  116  into the well  120  and reservoir. The next step  310  asks whether the flow of gas or foam  116  will be stopped before the carrier liquid  102  is injected into the well  120  and reservoir. In certain implementations, the flow of gas or foam  116  may stop and the carrier liquid  102  may be subsequently injected into the well  120 , as was shown in  FIG. 4 . In other implementations, the flow of gas or foam  116  may continue or not be stopped. In these implementations, the carrier liquid  102  may be injected into the well  120  at step  320  while the foam or gas  116  is also or simultaneously flowing into the well  120 . Next, the previous steps  300 ,  310 ,  320  may be repeated, if desired. The treatment may be ended at step  340 . 
         [0039]    Turning to the flowchart of  FIG. 6 , at step  400 , the gas or foam  116  and the carrier liquid  102  may be simultaneously injected into the well  120  and reservoir without any previous injections of the gas or foam  116  into the well  120 . The gas or foam  116  and the carrier liquid  102  may be connected at the wellhead  126  to be delivered downhole. The gas or foam  116  may mix with the carrier liquid  102  at the wellhead  126  or within the wellbore  118 . This step  400  may continue until the end of treatment at step  410 . 
         [0040]    Various modifications and additions can be made to the exemplary embodiments discussed without departing from the spirit and scope of the presently disclosed technology. For example, while the embodiments described above refer to particular features, the scope of this disclosure also includes embodiments having different combinations of features and embodiments that do not include all of the described features. Accordingly, the scope of the presently disclosed technology is intended to embrace all such alternatives, modifications, and variations together with all equivalents thereof.