You are an expert at summarizing long articles. Proceed to summarize the following text:

You are an expert at summarizing long articles. Proceed to summarize the following text: 
TECHNICAL FIELD 
       [0001]    The present invention relates generally to controlling well parameters, and more particularly to actively controlling the liquid level in wells by using various surface measurements. 
       BACKGROUND 
       [0002]    Oil and gas wells are ubiquitous in the petrochemical industry. During the production of oil and gas from a well, the downhole pressure of a well may drop below a level necessary to actively produce liquids from the well. A pump, sometimes termed a “beam pump” or a “sucker rod pump”, may be used to artificially lift the liquid in the well. In brief, these pumps often operate by moving a downhole pump barrel in and out of the liquid in the wellbore. One or more valves may be situated on the pump so that moving the pump in and out of the liquid in this fashion creates a sufficient amount of artificial lift to bring the liquid out of the well. If the liquid level in the wellbore declines to the point that the pump is no longer submerged, however, pump operation may suffer. For example, if the pump is no longer submerged, the pump may come in and out of contact with the liquid in the well as the pump is moved in and out of the wellbore. This may result in the pump pounding the surface of the liquid as it moves in and out of the liquid, a condition termed “fluid pounding”. Fluid pounding may undesirably cause pump failure by separating the pump from the sucker rod and/or by damaging the gear box or other surface components. 
         [0003]    To minimize fluid pounding, conventional systems often monitor the mechanical load on the sucker rod and the position of the pump downhole by using a load cell and position switches mounted to the surface of the pump. Once the fluid pounding condition is noticed, conventional systems often deactivate the pump for a predetermined period of time. This approach has several drawbacks. First, the pump must actually be experiencing a fluid pounding condition before it will be shut off, which may be harmful to the pump components. Second, the pump is powered down for a predetermined period of time regardless of the actual liquid level in the wellbore. Thus, when the predetermined time expires and the pump is turned back on, the fluid pounding condition may still exist. Also, because conventional systems turn the pump back on after a predetermined period of time, the pump may be off even when the liquid level has risen to a point where the fluid pounding condition would no longer exist if the pump were running. Fourth, analyzing the load cell for load characteristics may be complex. Lastly, maintenance costs associated with the load cell and position switches may undesirably add to the overall costs of the operating the well thus reduce profitability. Accordingly, there is a need for a system and method for controlling downhole liquid levels that addresses one of more of these deficiencies. 
       SUMMARY 
       [0004]    Methods and apparatuses are disclosed for measuring and controlling liquid levels in a well. Some embodiments may include apparatuses that further include a plurality of sensors, the plurality of sensors comprising: a first sensor coupled to the well, the first sensor configured to measure a casing pressure, a second sensor coupled to the well, the second sensor configured to measure a tubing pressure, and a third sensor coupled to a motor that is further coupled to the well, the third sensor configured to measure at least one characteristic of the motor, and a processor coupled to the plurality of sensors, wherein the processor calculates a level of liquid in the well based upon measurements of at least two of the plurality of sensors. 
         [0005]    Some embodiments may include methods that further include calculating liquid levels in a well, the method may comprise: reading a plurality of data measurements, calculating an annulus liquid level based upon at least two of the plurality of data measurements, determining if the liquid level is decreasing, and in the event that the liquid level approaches a predetermined location within the well, shutting off a motor coupled to the well. 
         [0006]    Some embodiments may include a system comprising: a processing unit and a plurality of sensors coupled to the processing unit and coupled to at least one well within the plurality of wells. The plurality of sensors may comprise: a first sensor coupled to the at least one well within the plurality of wells, the first sensor configured to measure a casing pressure, a second sensor coupled to the at least one well within the plurality of wells, the second sensor configured to measure a tubing pressure, and a third sensor coupled to a motor that is further coupled to the at least one well within the plurality of wells, the third sensor configured to measure at least one characteristic of the motor, wherein the processing unit calculates a level of liquid in the well based upon measurements of at least two of the plurality of sensors. 
         [0007]    Some embodiments may include an apparatus for measuring data from a well, comprising means for receiving at least one signal pertaining to the well, means for calculating a liquid level based upon the at least one signal, means for determining if the liquid level is decreasing, and in the event that the liquid level approaches a predetermined location within the well, means for shutting off a motor coupled to the well. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0008]      FIG. 1  illustrates an exemplary well pumping system. 
           [0009]      FIG. 2  illustrates an exploded view of a cross section of the well. 
           [0010]      FIG. 3  illustrates exemplary operations to control pump activity. 
           [0011]      FIG. 4  illustrates an exemplary embodiment for measuring the level of liquid in a well. 
       
    
    
       [0012]    The use of the same reference numerals in different drawings indicates similar or identical items. 
       DETAILED DESCRIPTION OF THE INVENTION 
       [0013]    The following discussion describes various embodiments that may determine the liquid level in a well. Although one or more of these embodiments may be described in detail, the embodiments disclosed should not be interpreted or otherwise used as limiting the scope of the disclosure, including the claims. In addition, one skilled in the art will understand that the following description has broad application. Accordingly, the discussion of any embodiment is meant only to be exemplary and is not intended to intimate that the scope of the disclosure, including the claims, is limited to these embodiments. 
         [0014]    Embodiments are disclosed that may allow the liquid level in a well to be calculated based upon one or more surface side measurements. The measurements may be based upon surface side parameters. For example, in some embodiments the measurements may be associated with the power consumption of a surface side motor, the motor&#39;s revolutions per minute, pressure in the casing of the well, pressure in the tubing of the well, etc. These parameters may be measured using sensors conventionally used at the surface of a well, and therefore, specialized load cells and/or position sensors may be unnecessary in determining the liquid level and in determining whether a fluid pounding condition is present. By calculating the liquid level, the pump&#39;s operation may be controlled to turn off prior to fluid pounding occurring, and therefore, the pump&#39;s components may be less likely to be damaged. Furthermore, the pump&#39;s operation may be controlled to turn back on without waiting for a predetermined time to expire so that the amount of time that the pump is on may be maximized. 
         [0015]      FIG. 1  illustrates a pump jack  100  capable of providing artificial lift to liquid produced from a well  105  drilled to a depth of a producing formation  103 . As used herein, the term “producing formation” generally refers to a strata of earth that may include liquid and/or gas of interest. While the producing formation  103  may be shown as generally orthogonal to the tubing and casing (e.g., as shown in  FIG. 2 ) this is for the sake of discussion. In fact it should be recognized that the producing formation  103  may be oriented in various ways. 
         [0016]    The liquid produced from the well  105  may be any variety of liquids such as oil and/or condensate (both of which are herein referred to as “oil”), water, and/or combinations of oil and water, which are sometimes called “emulsion”. Depending upon the embodiment, the pump jack  100  may include a motor  110 , a gear box  115  coupled to the motor, a beam  120  (sometimes referred to as a “walking beam”) coupled to the gearbox  115 , and a rod  125  coupled to the walking beam  120  via a weighted head  130  (sometimes referred to as the “horse head” of the pump jack  100 ). During operation, the motor  110  may move a set of pulleys  132 , which in turn may move a counter weight  135  to move the walking beam  120  and horse head  130  about a supporting structure  140 . Moving the walking beam  120  in this manner may result in the rod  125  moving up and down, thereby causing a downhole pump  145  coupled to the rod  125  to move within the liquid introduced to the production casing  205  from the producing formation  103 . As the downhole pump  145  moves within the liquid, the liquid may be pushed to the surface through the interior of the production tubing  220  (shown and discussed in greater detail with regard to  FIG. 2 ). 
         [0017]    As mentioned above, if the liquid level (designated as “LL” in  FIG. 2 ) drops to a level where the pump  145  is not fully submerged, then the rod  125 , the pump  145 , and/or the pump jack  100  may be damaged. Some embodiments may prevent this damage by actively monitoring the liquid level within the annular space between the production casing  205  and the production tubing  220  and shutting the pump jack  100  off when the liquid level approaches a level where the pump  145  is no longer submerged. Furthermore, some embodiments may calculate this liquid level without implementing specialized load cells and/or position sensors. For example, the liquid level may be determined by monitoring the well production data, pump data, and/or motor data. In other embodiments, one or more downhole sensors may be employed to measure the liquid level. 
         [0018]      FIG. 2  depicts an exploded view of a section  200  of the well  105 . The section  200  illustrates a casing  205  oriented in the ground to at least a depth of the producing formation  103 . The casing  205  may be made of a rigid material, such as metal piping, in order to prevent the walls of the well  105  from caving in and/or to prevent the well contents within the casing  205  (such as oil and gas), from entering another formation other than the producing formation  103 . In some embodiments, the well  105  may be drilled in such a manner that the well  105  is larger than the outside diameter of the casing  205 . In these embodiments, the annulus between the production casing  205  and the formation  103  and the bottom portion of the production casing  205  may be filled with a sealant  215 , such as concrete or clay grout as shown. 
         [0019]    The section  200  also illustrates a production tubing  220  oriented within the production casing  205  leaving an annulus  225  between the production tubing  220  and the production casing  205 . The production casing  205  may extend from surface side to the bottom of the well  105 . The production tubing  220  may extend from surface side to a point above the introduction of liquids and/or gas from the producing formation  103 . The overall length of the tubing is designated in  FIG. 1  as “TL”. During operation, liquid from the producing formation  103  may permeate one or more perforations  227  in the casing  205  and sealant  215  (shown in  FIG. 2 ) such that when the rod  125  and the pump  145  move within the production tubing  220 , liquid may be forced from the producing formation  103 , through the perforations  227 , and up through the production tubing  220 . Because the producing formation  103  may include mixtures of oil, gas, and/or water, the emulsion may be collected and produced through the tubing  220  whereas the annulus  225  may be used to collect and produce the gas. 
         [0020]    Referring still to  FIG. 1 , the liquid and gas collected downhole may be removed at the surface via a liquid pipe  150  and a gas pipe  155  respectively. The gas pipe may be coupled to a measurement device  156 , which in some embodiments may include a plate with an orifice that is situated within the gas pipe. During operation, the measurement device  156  may measure temperature, pressure, and differential pressure for volume calculations. 
         [0021]    In accordance with some embodiments, the liquid level LL may be calculated by measuring various parameters such as the casing pressure, tubing pressure, motor power consumption, motor speed, and/or physical parameters of the well  105 , such as the tubing length TL. In some embodiments, the liquid flow in the pump  145  over a single lift cycle and the pressure at the inlet of the pump  145  may be calculated. An exemplary LL calculation will now be presented based upon one or more surface side parameters available without implementing specialized load cells and/or position sensors often used in conventional systems. Although exemplary LL calculations are presented herein, it should be appreciated that numerous methods of calculating LL based upon one or more surface side parameters may be implemented that fall within the spirit and scope of this disclosure. 
         [0022]    Equation (1) represents an exemplary equation that may be used to calculate the flow rate Q in the pump  145  over a single lift cycle. 
         [0000]    
       
         
           
             
               
                 
                   Q 
                   = 
                   
                     
                       π 
                       · 
                       S 
                       · 
                       R 
                       · 
                       
                         E 
                         v 
                       
                       · 
                       
                         A 
                         IT 
                       
                     
                     
                       r 
                       · 
                       
                         C 
                         v 
                       
                     
                   
                 
               
               
                 
                   Eq 
                   . 
                   
                       
                   
                    
                   
                     ( 
                     1 
                     ) 
                   
                 
               
             
           
         
       
     
         [0023]    Turning to Equation (1), the variable S is the distance traveled by the rod  125  with each cycle of the pump jack  100 . Since the distance traveled by the rod  125  may be controlled by the up and down motion of the horse head  130 , the value of S may be a known value. The variable R is the speed of the motor  110  and may be measured in revolutions per minute (RPMs). In some embodiments, the RPMs may be measured using a magnetic pickup sensor  157  positioned adjacent to the motor  110  and coupled to a processor  160 . The processor may be preprogrammed to sample values from the sensor  157  and determine the RPMs based upon these measurements. Furthermore, the processor  160  also may be preprogrammed with the value of the distance the rod  125  travels with each cycle S, where the completion of a cycle may be related to a predetermined number of revolutions of the motor  110 . In this manner, the processor  160  may take a variety of forms such as a programmable logic controller, a microcontroller, and/or a computer system to name but a few implementations. 
         [0024]    The processor  160  may be coupled to a host computer  185 , which may be located in a geographically different location than the processor  160  in some embodiments. That is, the host computer. 185  may be located in a remote field office in a field of wells, or in some embodiments, the host computer  185  may be located in a vehicle that travels within the field of wells. Thus, the host computer  185  may be hardwired to the processor  160  and/or wirelessly coupled to the processor  160 . 
         [0025]    Referring back to Equation (1), the variable E v  in Equation (1) is the volumetric efficiency of the pump  145 . Generally speaking, the volumetric efficiency E v  refers to the theoretical flow rate of the pump  145  compared to the actual liquid flow rate from the liquid pipe  150 . The actual liquid flow rate from the liquid pipe  150  is often measured as part of the data associated with the production of the well  105 . Thus, the volumetric efficiency E v  may characterize the amount of leakage, or losses in volume in the pump  145 , per lift cycle. Exemplary values for the volumetric efficiency may range from 90-98%. The variable A IT  is the cross sectional area inside the tubing  220  as shown in Equation (2), where ID T  is the inside diameter of the tubing  220  as indicated in  FIG. 2 . 
         [0000]    
       
         
           
             
               
                 
                   
                     A 
                     IT 
                   
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         [0026]    The variable r in Equation (1) is the number of motor revolutions performed per lift cycle of the pump jack  100 . The variable C v  is the volume conversion factor. In some embodiments, the stroke length S and the inside diameter ID T  are measured in inches and therefore the volume conversion factor variable C v  may be 231 inches 3  per gallon. Thus, the dimensions for the flow rate of Equation (1) may be gallons per minute. 
         [0027]    Equation (3) represents an exemplary equation that may be used to calculate the pressure P INLET  at an inlet to the pump  145  using the flow rate Q calculated in Equation (1). 
         [0000]    
       
         
           
             
               
                 
                   
                     P 
                     INLET 
                   
                   = 
                   
                     
                       ( 
                       
                         
                           T 
                            
                           
                               
                           
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                         + 
                         
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         [0028]    Turning to Equation (3), the variable TP is the tubing pressure as measured at the liquid pipe  150 . In some embodiments, the tubing pressure TP may be measured using a pressure transducer  165  coupled to liquid pipe  150 . In some embodiments, the units for the tubing pressure TP is pounds per inch 2  gauge (PSIG). Akin to the measurements described with regard to Equation (1), the processor  160  may make analog measurements from such a transducer and calculate digital versions of the same for use in further processing. The variable TL is the tubing length (in feet) and is known when the pump jack  100  is constructed. The variable G L  is the gradient of the liquid being removed from the well  105  in pounds per foot. The variable A AT , as shown in Equation (4), is the cross sectional area of an annulus  230  formed between the outside diameter of the rod  125  (labeled as R D  in  FIG. 2 ), and the area inside the tubing A IT  (expressed in Equation (2)). 
         [0000]    
       
         
           
             
               
                 
                   
                     A 
                     AT 
                   
                   = 
                   
                     
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                          
                         
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         [0029]    The variable W in Equation (3) is power consumed by the motor  110  as it operates the pump jack  100 . In some embodiments, the power consumed W may be measured by the processor  160  by monitoring an ammeter  170  and/or wattmeter  175  coupled to the motor  110 . The variable Q in Equation (3) is the flow rate calculated in Equation (1) in gallons per minute. The variable C P  is the power conversion factor. In some embodiments, the variable C P  is equal to 0.435 Watts-Minutes-Inches 2  per Pound-Gallon. The variable E M  is the mechanical efficiency of the pumping system, which may include the pump  145  and/or the pump jack  100 . In some embodiments, the value of the variable E M  may be measured directly in the field after one or more of the components shown in  FIG. 1  have been deployed. 
         [0030]    The liquid level LL in the well  105  may be calculated by equating the downhole pressure at the pump inlet (per Equation (3)) with the downhole pressure profile of the casing  205 , also P INLET  as shown in Equation (5), and then solving for the liquid level LL. 
         [0000]        P   INLET   =CP+P   GC   +P   LC    Eq. (5) 
         [0031]    Referring to Equation (5), the variable CP is the casing pressure at the gas pipe  155 . In some embodiments, the processor  160  may couple to a pressure transducer  180  that is coupled to the gas pipe  155 , and therefore, the processor may make analog measurements and convert the same to digital form for further processing and/or transmission. The variable P GC  in Equation (5) is the pressure of the head of the gas in the casing and may be calculated as shown in Equation (6), where the units for Equation (6) may be Pounds per Foot in some embodiments. 
         [0000]    
       
         
           
             
               
                 
                   
                     P 
                     GC 
                   
                   = 
                   
                     
                       
                         G 
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         [0032]    The variable G G  is the gradient of the gas being removed from the annulus  225 . As mentioned above, the variable TL is the tubing length (in feet) and is known when the tubing  220  is installed in the well  105 . The variable A AC  is the cross sectional area of the annulus  225  as shown in Equation (7), where the variable ID C  is the inside diameter of the casing  205  in inches and the variable OD T  is the outside diameter of the tubing  230  in inches. 
         [0000]    
       
         
           
             
               
                 
                   
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         [0033]    Referring to Equation (8), an equation for the calculating the head pressure of the liquid in the casing P LC  is shown. The variable G L  is the gradient of the liquid being removed from the annulus  225  and the other variables in Equation (8) have been described above. 
         [0000]    
       
         
           
             
               
                 
                   
                     P 
                     LC 
                   
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         [0034]    Referring momentarily back to Equation (5), after Equations (6), (7), and (8) are substituted into Equation (5), an expression for P INLET  may be derived. This expression for P INLET  may be set equal to the expression for P INLET  of Equation (3) and the resulting expression may be solved for the liquid level LL. Making these substitutions and solving for the liquid level LL yields Equation (9). 
         [0000]    
       
         
           
             
               
                 
                   
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         [0035]    As shown in  FIG. 1 , the variable CC in Equation (9) represents the distance from the center of the liquid pipe  150  to the center of the gas pipe  155 . (The rest of the variables in Equation (9) were addressed above.) The liquid level LL in Equation (9) may be calculated by relying upon a combination of variables that are known when the tubing  220  is installed in the well  105  (e.g., diameter of tubing  220 ), variables that may be measured during operation of the pump jack  100  (e.g., motor RPMs), and variables that may be calculated based upon the measured variables (e.g., liquid flow rate). Notably, the variables for calculation of Equation (9) may be measured and the pump jack  100  may be prevented from entering a potentially damaging condition. Also, maintaining the sensors, such as the sensors  157 ,  170 , and/or  175 , may be more cost effective than maintaining the load cells and position sensors used in conventional systems to detect fluid pounding. Furthermore, operation of the pump jack  100  may be based upon the actual liquid level LL allowing the pump jack  100  to be shut down before the liquid level LL gets so low that fluid pounding occurs, which may result in prolonging the life of the pump jack  100 . 
         [0036]      FIG. 3  illustrates an exemplary operation  300  that may be implemented by the processor  160  in controlling operation of the pump jack  100 . The operations shown in  FIG. 3  may be used to calculate the liquid level LL in the well  105  and/or store well trending information in the processor  160 . In block  305 , various measurements may be made, such as power consumed by the motor  110 , current consumed by the motor  110 , RPMs of the motor  110 , casing pressure CP, and tubing pressure TP to name but a few. As mentioned previously, this may include the processor  160  measuring analog measurements from one or more sensors  157 ,  165 ,  170 ,  175 , and/or  180 , and converting these analog signals to digital form. In block  310 , the calculated variables may be calculated by the processor  160 , for example, by executing operations that perform the calculations of Equations (1)-(9). If well production (for example as measured coming out of the liquid pipe  150 ) is not stable and/or the liquid level is not increasing, then the processor  160  may determine if the liquid level LL is approaching the pump  145  as shown in block  325 . If the liquid level LL is approaching the pump  145 , then the motor  110  and/or pump  145  may be shut off per block  320 . 
         [0037]    Depending upon the embodiment and/or the particular pump  145  implemented, the liquid level LL that triggers the condition of block  325  may vary. For example in some embodiments, the liquid level LL at which the pump jack  100  is shut off may be where the pump  145  is no longer submerged. In the event the liquid level LL does not trigger the condition of block  325 , then the total on time of the pump  100  may be determined and compared with a predetermined maximum on-time for the pump  145 . This is illustrated in block  330 . In the event that the pump on-time exceeds a predetermined maximum value, then the motor  110  may be shut off per block  320 . If, however, the pump on-time does not exceed this predetermined value, control may flow back to block  305  as shown. 
         [0038]    While the motor  110  is shut off, the pump  145  also may be shut off. In this situation, the system no longer may be able to calculate the liquid level LL in the annulus using motor characteristics—i.e., the wattmeter  175  may read zero watts, the calculated horsepower may be zero HP, and/or the downhole pressure may not be calculable. Thus, in order to determine when the pump should be re-started with the motor off, it may be based on any number of non-liquid level LL parameters. The non-liquid level LL parameters may include a declining casing pressure CP, a increasing gas production flow rate, and/or a preset motor off time to name but a few. In this manner, the pump  145  and/or the motor  110  may be reactivated (as shown in block  335 ) if certain conditions occur. For example, as illustrated in block  340 , if the casing pressure CP declines below a predetermined value then the motor  110  and/or pump  145  may be reactivated. In some embodiments, the measured casing pressure CP value may be approximately  100  psig. For example, a typical operating casing pressure CP in coal-bed-methane wells may vary between 0 psig to 150 psig. 
         [0039]    As mentioned above, the measured CP along with gas production flow rate data may be useful to determine the re-start condition. Where there is decreasing CP and increasing gas flow rate, the liquid level LL will most likely be increasing therefore the condition may be good to start the pump to remove fluids. In some wells increasing CP and increasing gas flow rate may also indicate an increasing liquid level LL therefore the condition may be good to start the pump to remove fluids. If the casing pressure CP is above this predetermined value, then the well&#39;s gas production may be checked to see if it is within a predetermined value as shown in block  345 . The well&#39;s liquid and gas production may be determined by examining flow meters (not necessarily shown in  FIG. 1 ) coupled to the liquid pipe  150  and the gas pipe  155 . In some embodiments, the gas production may be calculated according to standards set forth by the American Gas Association (AGA), such as AGA-3 and AGA-8. If the well production is above this predetermined level, then the motor  110  and/or pump  145  may be reactivated. In the event that the well production is not above this predetermined value, then the motor  110  and/or pump  145  may remain off until the processor  160  has determined that a predetermined elapsed time has transpired per block  350 . Once the processor  160  determines that the predetermined time has elapsed, then the motor  110  and/or pump  145  may be reactivated per block  335 . In the event that the predetermined time has not elapsed, or if the motor  110  and/or pump  145  has been reactivated per block  335 , then control flows back to block  305 , where the processor  160  may again read and store various measured variables, for example, as part of determining the trends associated with well  105 . 
         [0040]    As described above, the liquid level LL in block  325  may be based upon calculations, such as those presented in Equation (9). In some embodiments, the liquid level LL may be determined by one or more sensors located in the well  105 . As shown in  FIG. 4  the well  105  may include one or more floating objects  405 A-B. In some embodiments, the floating objects  405 A-B may include lightweight spherical structures, such as hollow plastic spheres, each having a radio-frequency-identification (RFID) transmitters. The RFID transmitters may be any variety, such as passive, active, and/or semi-passive. 
         [0041]    During operation, the RFID transmitters may transmit one or more signals to one or more receiving antennas  410 A-B positioned in the well  105 . In some embodiments, the one or more receiving antennas  410 A-B may be integrated within the casing  205 . In other embodiments, the antennas  410 A-B may be suspended from a cable  415  in the annulus  225 . Further, the one or more antennas  410 A-B may be positioned in predetermined locations within the well  105  such that the desired liquid level LL is located halfway between the antenna  410 A and  410 B. The floating objects  405 A-B may change position with the change in liquid level LL of the well  105 , and therefore, the antennas  410 A and/or  410 B may receive signals from the floating objects  405 A-B as they approach the antennas  410 A-B. In some embodiments, the antennas  410 A-B may be coupled to the processor  160  and the processor  160  may be used to determine the overall liquid level LL in the well  105 . 
         [0042]    Although two objects  405 A-B are shown in  FIG. 4 , it should be appreciated that any number of floating objects are possible. Also, in some embodiments, each of the objects  405 A-B may have different densities such that they may float at different levels within the well  105 . Further, some embodiments may include multiple receivers  410 A-B such that the position of the floating objects  405 A-B, and therefore the liquid level LL—may be triangulated, for example by the processor  160 . In addition, although  FIG. 4  illustrates wirelessly coupling the floating objects  405 A-B to the antennas  410 A-B, it should be appreciated that the floating objects  405 A-B may be physically coupled to the antennas or other such pickup device. For example, the floating objects  405 A-B may be hardwired to a pickup sensor to indicate liquid level instead of using RFID tags. 
         [0043]    Although the present invention has been described with reference to preferred embodiments, persons skilled in the art will recognize that changes may be made in form and detail without departing from the spirit and scope of the invention. For example, the disclosed methods of determining a well&#39;s liquid levels and trending data may be applied to naturally producing wells (i.e., wells that do not use the pump jack  100 ) by modifying the calculations described above accordingly.

Summary:
Methods and apparatuses are disclosed for measuring and controlling liquid levels in a well. The apparatus may include a plurality of sensors, the plurality of sensors comprising: a first sensor coupled to the well, the first sensor configured to measure a casing pressure, a second sensor coupled to the well, the second sensor configured to measure a tubing pressure, and a third sensor coupled to a motor that is further coupled to the well, the third sensor configured to measure at least one characteristic of the motor, and a processor coupled to the plurality of sensors, wherein the processor calculates a level of liquid in the well based upon measurements of at least two of the plurality of sensors.