Patent Publication Number: US-11649705-B2

Title: Oil and gas well carbon capture system and method

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application is a continuation-in-part (CIP) of and claims priority in PCT/US20/20473, filed Feb. 28, 2020; is related to U.S. Non-Provisional patent application Ser. No. 16/110,945, filed Aug. 23, 2018, which is a non-provisional of U.S. Provisional Patent Application No. 62/549,036 Filed Aug. 23, 2017, all of which are incorporated herein by reference. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates generally to improving currently-used artificial lift systems and methods for the production of oil, natural gas and water from vertical and horizontal wellbores, and methods of use thereof, and more specifically to optimizing well and field productivity in addition to lowering power usage by improving pump efficiency leading to lower operating costs on a per unit basis, optimal field and well production, less-frequent pump failures and minimizing or eliminating natural gas flaring and venting. This benefits carbon capture, operating costs, future capital costs, and in certain cases revenue due to an increase in recoverable reserves at the well and field level while reducing or eliminating natural gas wastage via flaring and venting. 
     2. Description of the Related Art 
     Current production methods for wells on artificial lift with natural gas production tend to be inefficient from the aspect of the pump and input power usage. Gas enters the pump, which lowers pump efficiency, decreases pump life and generally creates problems for operating the well. When operators use intermittent timing cycles to operate the pump, the timing cycle is based on the well-operator-inputs to a manual type clock and timer. There is no feedback loop in the described traditional currently-used system that allows for optimizing both pump and well performance based on actual real-time data collected at the well, nor is there commonly a mechanism used to maximize pump efficiency driven by a real time feedback loop. This lack of real-time data analysis also provides no predictive maintenance information on pump operation and increases outage times when sudden pump failures occur. 
     Another production method sometimes used involves incorporating what is known as a “Pump Off Controller” (POC) procedure, which attempts to maximize the pumping-system (not necessarily the well producing horizon itself) efficiency by measuring operating parameters such as the stress/strain relationship on the polish rod, and possibly input parameters at the prime mover. POCs do include feedback via parameters being measured, but the overall system efficiency is limited due to changing flow regimes at the pump intake, and are beyond the control of the POC. 
     Still further, current oil and gas production methodologies rely on venting and flaring excess natural gas. Such practices give rise to environmental concerns. Moreover, they compromise overall system efficiencies. 
     Heretofore, there has not been available a system or method for using real-time, instantaneous well performance data to optimize well production by recognizing changing downhole flow regimes and actively changing same to improve power system and pump efficiency performance, and further increasing reservoir production and recovery factors, with the advantages and features of the present invention. Moreover, there has not been available a system or method with the carbon capture advantages of the system and method of the present invention. 
     SUMMARY OF THE INVENTION 
     The present invention generally provides a novel carbon capture system and method for using data acquired at the well by gas metering and taking advantage of the relationship between flow rate and impact on flow regimes in the well in such a way as to optimize the reservoir performance of the well, increasing down-hole pump efficiency, reducing input power requirements, providing pump predictive maintenance information, minimizing or eliminating natural gas flaring and venting, and optimizing carbon capture across the entire gathering system when used in a field-wide application. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The drawings constitute a part of this specification and include exemplary embodiments of the present invention illustrating various objects and features thereof. 
         FIG.  1    is a schematic, block diagram of an oil and gas production well system embodying an aspect of the present invention. 
         FIG.  2    is a fragmentary, elevational view of an oil and gas production wellstring 
         FIGS.  3   a - 3   c    show a flowchart of a method of the present invention. 
         FIG.  4    is a schematic, block diagram of an oil and gas production well system embodying a modified or alternative aspect of the present invention. 
         FIGS.  5   a - 5   c    show a flowchart of a modified or alternative embodiment method of the present invention. 
         FIGS.  6   a - 6   c    show a simple digital (on/off) control scheme for use with the system and method of the present invention. 
         FIGS.  7   a - 7   c    show a complex (variable) control scheme for use with the system and method of the present invention. 
         FIG.  8    shows a schematic, block diagram of an oil and gas production well system embodying another modified or alternative aspect of the present invention with carbon capture, anti-flaring and anti-venting features. 
         FIG.  9    shows a local connection and control schematic for the system shown in  FIG.  8   . 
         FIG.  10    is a diagram showing well response as a function of wellhead pressure with respect to time for the system. 
         FIG.  11    shows states of control for the system. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     I. Introduction and Environment 
     As required, detailed aspects of the present invention are disclosed herein, however, it is to be understood that the disclosed aspects are merely exemplary of the invention, which may be embodied in various forms. Therefore, specific structural and functional details disclosed herein are not to be interpreted as limiting, but merely as a basis for the claims and as a representative basis for teaching one skilled in the art how to variously employ the present invention in virtually any appropriately detailed structure. 
     Certain terminology will be used in the following description for convenience in reference only and will not be limiting. For example, up, down, front, back, right and left refer to the invention as orientated in the view being referred to. The words, “inwardly” and “outwardly” refer to directions toward and away from, respectively, the geometric center of the aspect being described and designated parts thereof. Forwardly and rearwardly are generally in reference to the direction of travel, if appropriate. Said terminology will include the words specifically mentioned, derivatives thereof and words of similar meaning. Well “backside” refers to the annular space between the well tubing and casing, and is the conduit of production for the gas stream and any liquids the well can produce while flowing naturally. Tubing refers to a small diameter pipe system that, in an artificially lifted well, is intended to be the conduit of travel for liquid phases of both oil and water. Well “loading” refers to a state of gas flow that is impeded by simultaneous liquids production that slows the rate of gas flow rate, ultimately to a no-flow condition if loading is allowed to continue. 
     II. Systems Embodying Aspects of the Invention 
       FIG.  1    shows an oil and gas production well control system  2  including a well  3  and a controller  4 . The controller  4  can be connected to the Internet (i.e., “cloud”)  6 , e.g., wirelessly or directly. The system  2  can perform computational analysis in the cloud  6  by providing data input from the controller  4 , which can download commands from the cloud  6 . Alternatively, data processing and system control functions can be provided by a standalone computer or a network of computers. Still further, such processing capability can be incorporated in “smart” components of the system  2 . 
     The system  2  includes a wellstring (multiple production wells can be included in the system and driven by a single-point cloud/software system). Conventional production wellstrings can include an outermost casing  10 , an intermediate liner  12  and an innermost tubing  14 . Such production wellstring components can be installed downhole as individual sections connected at their respective ends. Casings  10  can be cast-in-place downhole. Liners  12  commonly terminate subsurface, and can be suspended from the casing  10  by hangers  16 . U.S. Pat. No. 7,090,027 shows casing hanger assemblies, and is incorporated herein by reference. The wellstring includes a first backside  18  comprising an annular space between the liner  12  and the tubing  14 . A second backside  20  comprises an annular space between the casing  10  and the tubing  14 . The wellstring is connected to a pump subsystem  35 , which includes a motor  32  and a pump motor control sensor  34 . The pump subsystem motor  32  can reciprocate a conventional pump jack (not shown), or drive various other downhole pump configurations such as progressive cavity and electric submersible pumps. Various alternative production well constructions can include the control system and perform the method of the present invention. 
     As shown in  FIG.  1   , well tubing production (generally oil and water in liquid phase) exits a wellhead  5  via a tubing valve  22  and backside  20  production (generally gas, which can include entrained liquids) exits the wellhead  5  via a backside valve  24 , which flows through a control valve  26  connected to the controller  4 . The controller  4  can be programmed to provide positioning signals to the control valve  26  in response to controller input, including control valve  26  positional status, preprogrammed operating parameters and conditions, and pressure data detected at upstream and downstream transducers  28 ,  30 , which data can be utilized in computing system output flow rates. 
     The controller  4  is also interactively connected to a motor or prime mover  32 , which can include a pump motor control/sensor  34 . The motor  32  can utilize variable frequency drive (“VFD”) technology. Motor  32  status conditions can be running, stopped or hand-off automatic (“HOA”), which status conditions can be input to the controller  4 . 
     Production enters a phase separator subsystem  36  via the valves  22 ,  26 . The phase separator subsystem  36  includes a gas/liquid phase separator  38  wherein gas and liquid (i.e., oil and water) phases are separated, preferably at the surface. The gas flow proceeds down a sales line  39  that typically includes a differential pressure (P DIFF ) meter  42  to monitor and record the natural gas production. This measurement is done using typical gas parameters as a function of temperature and pressure, as well as using an orifice plate  40  of known restriction such that the instantaneous production rate can be calculated via the measured pressures on either side of the orifice plate  40 . A difference in pressure between these two points of measurement (P DIFF ) indicates flow rate. The instantaneous well gas production is directly proportional to the P DIFF  recorded at the meter  42 , which records both orifice plate  40  well side and flowline side measured pressures, the calculated P DIFF , and the calculated production flow rate as functions of time via an internal clock. 
     The production flow rate can be input to the controller  4 . Alternatively, P DIFF  can be independently derived from the upstream and downstream pressure transducers  28 ,  30 . It should be noted that if data from a flow meter is available to the system for P DIFF , then pressure transducer  30  is not required as part of the system. Custody (ownership) of the gas output can transfer at the digital flow meter  42 , which operates as a discrete external input source. Alternatively, the custody transfer can occur downstream whereby the alternative configuration design choice based on an as-built design at the well site with upstream and downstream pressure transducers  28 ,  30  may be preferred. Such P DIFF  is proportional to gas flow volume throughput and can provide quantity data as needed for the gas sales line  39  downstream of the system  2 . Liquid output from the gas/liquid separator  38  enters an oil/water separator  44 , and exits to further separation, disposal, oil sales, tankage, etc. 
     The system  2  uses instantaneous P DIFF  information and, via computation in a proprietary algorithm using cloud architecture, determines the optimal state of operation of both the downhole pump (controlled by the motor  32  located at the surface wellhead  5 ) and the automated control valve  26  between the well first backside or annulus  18  and the gas/liquid separator  38 , as shown in  FIG.  1   . The upstream pressure measurement transducer  28  (between the wellhead  5  and the control valve  26 ) inputs pressure data to the controller  4  for use with flow meter  42  data. The P DIFF  can be supplied by the flow meter  42 , or if this is not feasible, by using the wellhead upstream pressure transducer  28  in combination with the (optional) downstream transducer  30  inserted into the flowline on the downstream side of the orifice plate  40 . The control system  2  is pump “agnostic” and can be used with reciprocating tubing insert pumps, progressive cavity pumps, electric submersible pumps, etc. 
     In a high gas-flow-rate condition via the second back side  20 , the operating downhole pump subsystem  35  will intake gas as well as liquids during the pumping cycle. In the same condition, the flow meter  42  will register a ‘high’ P DIFF . During this condition there is no need to operate the pump subsystem  35 , and the system  2  recognizes this regime condition and optimizes by the well controller  4  opening the control valve  26  and maintaining the downhole pump subsystem  35  condition in “Off.” As the well  3  continues to operate in this condition, both liquids and gas are flowing into the well  3 , and both are attempting to flow via the backside  18 . As the bottom hole pressure of the well struggles to lift both the liquids and gas from the well  3  due to an increase (gradual or sudden) in dynamic head, the flow rate decreases. This will be evidenced as decreasing P DIFF  at the flow meter  42  (or independently derived as described elsewhere if flow meter  42  is not available). The cloud software  6  will continue monitoring P DIFF  until the logic determines a necessity to close the control valve  26  and begin a pumping condition cycle. 
     When the controller  4  initiates the pumping condition, the control valve  26  is automatically closed, halting fluid upflow in the first backside  18  (V UPFLOW =0). Gravity segregation will naturally occur in this zero-velocity backside environment, and the liquid phases will ‘fall’ to the bottom of the well  3  for intake by the pump subsystem  35 . 
     A chemical input subsystem  46  can be connected to the well  3  and controlled by the controller  4  for controlling well treatment. Treatment plans are commonly implemented with such chemical input subsystems, which can inject anti-scaling, paraffin-eliminating and other control chemicals downhole. As the P DIFF  naturally decreases after a flowing cycle and immediately after shutting in the control valve  26 , the controller  4  would initiate operation of the chemical input subsystem  46  (e.g., pumps) to place chemicals in the backside ( 18  and/or  20 ) of the well  3  as it changes state from production to gravity segregation in a pumping cycle. 
     The controller  4  will then start the bottom-hole pump subsystem  35  via the (surface or downhole, depending on lift system employed at well) motor  32  and commence pumping since liquids are now at the pump intake and gas is segregating upward, thus creating a rising pressure seen at the pressure transducer  28  located near the control valve  26 . The cloud  6  can either be programmed to calculate the fluid production based on well operating parameters, or a sensor  34  can be added to the system  2  to actually measure the pump motor rotations or stroke rates with this data supplied to the controller  4 , thus enabling a more robust liquid production calculation. 
     The cloud  6  can incorporate machine learning techniques to optimize the well production as a function of run time of the pump subsystem  35 , as well as establishing well performance optimization based on analysis of various pressure build up and flow-down rates and time frames seen at the control valve pressure transducer  28  and P DIFF , respectively. Certain wellbore construction and operating parameters can be input into the software architecture and the software will determine superficial gas velocities for all wellbore topologies present. The system  2  will estimate critical velocities for each discrete wellbore topology and will use this information as a baseline for determining the starting point for the shut-in state of the system  2 , thus maximizing the in situ well energy and thereby increasing both the life and the expected ultimate reserves recovery of the well. During the shut-in phase, the system  2  will monitor, record and learn from the nature of the pressure buildup: slope(s) of buildup, time to build to certain pressures, etc. The cloud  6  can be programmed to perform a Fast Fourier Transform on each buildup pressure and note the frequency domain and distribution of same, comparing each signature with various production and pressure buildup characteristics as an aid in determining when various production stages are contributing to wellbore fillage and production. 
     The control system  2  can warn of impending pump failure by continually analyzing the time cycle duration and subsequent number of pump strokes required to obtain a given backside pressure buildup. The control system  2  will also lead to optimization of existing gathering systems and compression when used on a field-wide basis. Wells at a greater distance from field compression will have greater line pressure losses to overcome compared to wells closer to the compressor for a given flow rate. By monitoring and regulating flow times and rates of all wells on the system as well as actual system pressures, the cloud  6  can determine the optimum time to produce wells further down the gathering system line by coordinating the flow time with pumping times of other wells on the system to lower the backpressure seen at the producing wells. 
     III. Method Embodying Aspects of the Invention 
       FIGS.  3   a - 3   c    show a flowchart for a non-limiting, exemplary method of practicing the present invention. Various other steps, sequences and operating parameters can utilize the inventive method. 
     IV. Systems Embodying Alternative Aspects of the Invention 
       FIG.  4    shows an oil and gas production well control system  102  comprising an alternative aspect or embodiment of the present invention and including a well  103  and a local controller  104 . The local controller  104  can be connected to the Internet (i.e., “cloud”)  106 , e.g., wirelessly or directly. The system  102  can perform computational analysis in the cloud  106  by providing data input from the local controller  104 , which can download commands from the cloud  106 . 
     The system  102  includes a wellstring (multiple production wells can be included in the system and driven by a single-point cloud/software system), as shown in  FIG.  5   . Conventional production wellstrings can include an outermost casing, an intermediate liner and an innermost tubing. Such production wellstring components can be installed downhole as individual sections connected at their respective ends. Casings can be set-in-place downhole. Liners commonly terminate subsurface, and can be suspended from the casing by hangers. U.S. Pat. No. 7,090,027 shows casing hanger assemblies, and is incorporated herein by reference. The wellstring includes a first backside comprising an annular space between the liner and the tubing. A second backside comprises an annular space between the casing and the tubing. The wellstring is connected to a pump subsystem, which includes a motor and a pump motor control sensor. The pump subsystem motor can reciprocate a conventional pump jack (not shown), or drive various other downhole pump configurations, such as progressive cavity and electric submersible pumps. Various alternative production well constructions can include the control system and perform the method of the present invention. 
     As shown in  FIG.  4   , well tubing production (generally oil and water in liquid phase) exits a wellhead  105  via a tubing valve  122  and backside production (generally gas, which can include entrained liquids) exits the wellhead  105  via a backside valve  124 , which flows through a control valve  126  connected to the local controller  104 . The local controller  104  can be programmed to provide positioning signals to the control valve  126  in response to controller input, including control valve  126  positional status, preprogrammed operating parameters and conditions, and pressure data detected at upstream and downstream transducers  128 ,  130 , which data can be utilized in computing system output flow rates. 
     The local controller  104  is also interactively connected to a motor or prime mover  132 , which can include a pump motor control/sensor  134 . The motor  132  can utilize variable frequency drive (“VFD”) technology. Motor  132  status conditions can be running, stopped or hand-off automatic (“HOA”), which status conditions can be input to the local controller  104 . 
     Production enters an existing surface phase separator subsystem  136  via pipe routing through valves  122 ,  126 . The phase separator subsystem  136  includes a gas/liquid phase separator  138  wherein gas and liquid (i.e., oil and water) phases are separated. The gas flow proceeds down a sales line  139  that typically includes a differential pressure (P DIFF ) meter  142  to monitor and record the sold natural gas production. This measurement is done using typical gas parameters as a function of temperature and pressure, as well as using an orifice plate  140  of known restriction such that the instantaneous production rate can be calculated via the measured pressures on either side of the orifice plate  140 . A difference in pressure between these two points of measurement (P DIFF ) indicates flow rate. The instantaneous well gas production is directly proportional to the P DIFF  recorded at the meter  142 , which records both orifice plate  140  well side and gathering line measured pressures, the calculated P DIFF , and the calculated production flow rate as functions of time via an internal clock. If access to data from the sales meter is not available due to custody transfer, or other data and/or physical blockage issues, differential pressure can be derived by other means internal to the system  102 . For many producing oil and gas wells it is not always the case that all gas produced can enter the gathering system  139  due to pressure limitations. Wells that find themselves in this operating condition will typically either flare (burn at site) or vent (to atmosphere) the excess gas. Wells with flaring systems would include a tee to the flare(s) between the separator  136  and the orifice plate  140  for the custody transfer sales gathering system meter  142 . Wells that vent may vent from a dedicated line or may simply vent via a phase separator  136 . 
     The production flow rate can be input to the local controller  104  if available via meter  142 . Alternatively, P DIFF  can be independently derived from the upstream and downstream pressure transducers  128 ,  130  if physical access to gathering system side of orifice plate is not possible. As shown in dashed lines in  FIG.  4   , the pressure transducer  130  can alternatively be located on either the operator (left in  FIG.  4   ) side of the digital flow meter  142  and the orifice plate  140 , or on the customer (right in  FIG.  4   ) side. It should be noted that if data from a flow meter is available to the system for P DIFF , then pressure transducer  130  is not required as part of the system. 
     Custody (ownership) of the gas output can transfer at the digital flow meter  142 , which operates as a discrete external input source to the local controller  104 . Alternatively, the custody transfer can occur downstream whereby the alternative configuration design choice based on an as-built design at the well site with upstream and downstream pressure transducers  128 ,  130  may be preferred. Such P DIFF  is proportional to gas flow volume throughput and can provide quantity data as needed for the gas sales line  139  downstream of the system  102 . Liquid output from the gas/liquid separator  138  enters an oil/water separator  144 , and exits to further separation, disposal, oil sales, tankage, etc. 
     The system  102  uses instantaneous PDWF information and, via computation in a proprietary algorithm using cloud architecture, determines the optimal state of operation of both the downhole pump (controlled by the motor  132  located at the surface wellhead  105 ) and the automated control valve  126  between the well first backside or annulus and the gas/liquid separator  138 , as shown in  FIG.  4   . The upstream pressure measurement transducer  128  (between the wellhead  105  and the control valve  126 ) inputs pressure data to the local controller  104  for use with flow meter  142  data. The PDWF can be supplied by the flow meter  142 , or if this is not feasible, by using the wellhead upstream pressure transducer  128  in combination with the (optional) downstream transducer  130  inserted into the flowline on the downstream side of the last stage of separation for the gas. Ideally this would be on the gathering system side of the orifice plate, but if not possible, can be located upstream of the sales meter and derived separately. The control system  102  is pump “agnostic” and can be used with reciprocating tubing insert pumps, progressive cavity pumps, electric submersible pumps, etc. 
     In a high gas-flow-rate condition via the second back side, the operating downhole pump subsystem  135  will intake gas as well as liquids during the pumping cycle. In the same condition, a ‘high’ P DIFF  state is present. During this condition there is no need to operate the pump subsystem  135 , and the system  102  recognizes this regime condition and optimizes by the well local controller  104  opening the control valve  126  and maintaining the downhole pump subsystem  135  condition in “Off.” As the well  103  continues to operate in this condition, both liquids and gas are flowing into the well  103 , and both are attempting to flow via the backside. As the bottom hole pressure of the well struggles to lift both the liquids and gas from the well  103  due to an increase (gradual or sudden) in dynamic head, the flow rate decreases. This will be evidenced as decreasing P DIFF  at the flow meter  142  (or independently derived as described elsewhere if flow meter  142  is not available). The cloud software  106  will continue monitoring P DIFF  until the cloud-based algorithm determines a necessity to close the control valve  126  and begin a pumping condition cycle. 
     When the local controller  104  initiates the pumping condition, the control valve  126  is automatically closed, halting fluid upflow in the first backside (V UPFLOW =0). Gravity segregation will naturally occur in this zero-velocity backside environment, and the liquid phases will ‘fall’ to the bottom of the well  103  for intake by the pump subsystem  135 . 
     A chemical input subsystem  146  can be connected to the well  103  and controlled by the local controller  104  for better control of well chemical treatment. Treatment plans are commonly implemented with such chemical injection pumps and systems, which can inject anti-scaling, paraffin-eliminating and other control chemicals downhole. As the P DIFF  naturally decreases after a flowing cycle and immediately after shutting in the control valve  126 , the local controller  104  would initiate operation of the chemical input subsystem  146  (e.g., pumps) to place chemicals in the backside of the well  103  as it changes state from flowing backside production to gravity segregation in the pumping cycle. 
     The local controller  104  will then start the bottom-hole pump subsystem  135  via the (surface or downhole, depending on lift system employed at well) motor  132  and commence pumping since liquids are now at the pump intake and gas is segregating upward, thus creating a rising pressure seen at the pressure transducer  128  located near the control valve  126 . The cloud  106  can either be programmed to calculate the fluid production by the pump based on well and pump operating parameters, or a sensor  134  can be added to the system  102  to actually measure the pump motor rotations or stroke rates with this data supplied to the local controller  104 , thus enabling a more robust liquid production calculation. 
     The cloud  106  can incorporate machine learning techniques to optimize the well production as a function of run time of the pump subsystem  135 , as well as establishing well performance optimization based on analysis of various pressure build up and flow-down rates and time frames seen at the control valve pressure transducer  128  and P DIFF , respectively. Certain wellbore construction and operating parameters are input into the software architecture and the software will determine superficial gas velocities for all wellbore topologies present. The system  102  will estimate critical velocities for each discrete wellbore topology and will use this information as a baseline for determining the starting point for the shut-in state of the system  102 , thus maximizing the in situ well energy, decreasing gas volumes that are vented and/or flared thereby improving local air quality in addition to increasing the expected ultimate reserves recovery of the well. During the shut-in phase, the system  102  will monitor, record and learn from the nature of the pressure buildup: slope(s) of buildup, time to build to certain pressures, etc. The cloud  106  can be programmed to perform a time to frequency transformation on each buildup and flow down pressure cycle and note the frequency domain and distribution of same, comparing changing harmonic signatures with various production and pressure buildup characteristics in determining the state of inflow performance while flowing and pump state while pumping. 
     The control system  102  can warn of impending pump failure by continually analyzing the time cycle duration and subsequent number of pump strokes required to obtain a given backside pressure buildup. The control system  102  will also lead to optimization of existing gathering systems and compression when used on a field-wide basis. Wells at a greater distance from field compression will have greater line pressure losses to overcome compared to wells closer to the compressor for a given flow rate. By monitoring and regulating flow times and rates of all wells on the system as well as actual system pressures, the cloud  106  can determine the optimum time to produce wells further down the gathering system line by coordinating the flow time with pumping times of other wells on the system to lower the backpressure seen at the producing wells. 
     Continuous monitoring of pressures and flow rates of the produced well-gas also allows the system  102  to potentially decrease or eliminate the amount of flared and or vented gas. System  102  flare-volume control capacity is dependent on both well and gathering system restraints. However, the system  102  can inherently sense whether the well can or cannot flow gas into the gathering system via measurement from pressure transducers  128  and  130 . Should access to a local custody transfer meter  142  be available, then sales gathering system  139  pressure status would be known from  142  in lieu of transducer  130  with  130  being redundant to the system. Natural gas going to flare or vent is caused by one of two limiting boundary conditions, both of which are constantly and routinely monitored by the control system  102 . Limiting boundary condition 1 occurs when the sales gathering system  139  pressure exceeds that of the well, measured by pressure transducer  128 . Limiting boundary condition 2 occurs when the well pressure at transducer  128  exceeds the value allowed by the gathering system  139 . This gathering system limited pressure value would be one of the inputs to the system program as referenced in  FIG.  5   a   . Flaring/venting volume reduction by system  102  to boundary condition 1 involves controlling control valve  126  such that pressure is built up within the well allowing access to the gathering system when low well head pressure occurs, directly correlating to low gas velocity. Flaring/venting volume reduction by system  102  to boundary condition 2 involves regulating the pressure drop across control valve  126  via instantaneous throttling of same to create a suitable pressure drop allowing well gas to the enter the gathering system. Over time the system  102  records and accurately predicts pressure buildup as a function of time from historical data limiting the pressure overshoot as one of the functions of the machine learning software. Systems Embodying Alternative Aspects of the Invention 
     V. Methods Embodying Additional Alternative Aspects or Embodiments of the Invention 
       FIGS.  5   a - 5   c    show a flowchart for a non-limiting, exemplary method of practicing the present invention. Various other steps, sequences and operating parameters can utilize the inventive method. 
       FIGS.  6   a - 6   c    show a digital (binary, on/off) control scheme for the present invention with the local controller  104  configured for receiving various operating parameter inputs and providing outputs including valve and motor operating signals at  126  and  132 , respectively. Sequential stage times are shown in a pressure vs. time graph ( FIG.  6   b   ) for a repetitive cycle with a pressure build-up stage, a “burp” stage and a pump stage.  FIG.  6   c    shows the pump states (on and off) and the valve states (open and closed) in relation to the stage cycles. 
       FIGS.  7   a - 7   c    shows a complex (variable) control scheme for the present invention, with a local controller  104  receiving analog inputs for motor and valve status. Analog outputs control motor and valve operation. For example, the motor control outputs can control speed and run/stop. A variable frequency drive (VFD) can receive such output signals and can be connected to the pump motor  132 . The VFD can provide position information corresponding to valve status (variable between open and closed) in a feedback loop with valve status as an analog input to the local controller.  FIG.  7   b    further shows a chart of pressure vs. time for pump cycles, e.g., pressure build-up stage, “burp” stage (lost sales) and the pressure effects of well slugs on the pump during the slugging stage. The pressure values corresponding to the pump and valve states are also shown. Valve control signals from the local controller  104  generally respond to the pressure values sensed in the system. Pump states ranging from off to highest speed and valve states ranging from closed to fully open are also shown corresponding to different system pressure stages (e.g., build-up, gas to sales, possible gas flare and pump and pressure surge buildup due to slugging stage). 
     The present invention enables operators to minimize flaring by proactively controlling well-specific pressure build-ups and well loading. Sufficient gas quantities can be accumulated from a producing well or field to enable cost-effective storage, transport and commercial sales. Ratios of gas quantities sold vs. flared can be increased. Various mathematical modeling techniques can be utilized with the present invention. For example, regression analysis techniques using parameters such as pressures, oil and gas pricing and futures markets can be factored in to optimize profitability. Moreover, oil and gas well producing controls of the present invention can be utilized by operators in determining wells to “kill” (e.g., with fluid), reactivate and maintain in reserve. Such parameters also affect mineral rights lease values and other commercial business management considerations. 
     VI. Additional Alternative Aspects or Embodiments of the Invention 
       FIGS.  8 - 11    show another modified or alternative embodiment of the present invention comprising a gas capture, anti-flaring and anti-venting system  202 . A motor control subsystem  203  includes a local controller at the well  204 , a well pump system  205 , computational analysis (e.g., in the cloud)  206  receiving data uploaded from the local controller  204  and downloading commands thereto. 
     The well pump system  205  receives oil and gas from the well tubing, at a well tubing manual valve  222 . A chemical input subsystem  246  can be connected to the well  203  and controlled by the controller  4  for controlling well treatment. Input from the first well backside is received at manual valve  224  and proceeds to an adjustable control valve  226  for input to phase separators  236 , including a gas/liquid phase separator  238  and an oil/water separator  244 . Output from the gas/liquid separator can be received by an orifice plate  240  for supplying gas sales. A digital flow meter  242  can receive output from the gas/liquid phase separator  238 , either upstream or downstream of the orifice plate  240 . A pressure transducer  230  can also be connected either upstream or downstream of the orifice plate  240  and provides signal input to the local controller  204 . The pressure transducer  230  can be eliminated from the system  202  if data from the digital flow meter  242  is available. Third parties, such as customers, pipeline operators and others, can provide the digital flow meter  242 . Moreover, the connection between the phase separators  236  and the custody transfer orifice plate  240  can be specific to the piping design at the installation site and accommodate transactions among producers, customers and others involved in energy transactions. 
       FIG.  9    shows a load connection and control schematic for the system  202 . Wellhead pressure  228  and gathering system  239  pressure  230  are input as analog signals to the local controller  204 , which also receives analog input from: the motor control subsystem  235  controlling the motor-driving pump  232 ; and the control valve  226 . The control valve  226  can be controlled by analog output from the local controller  204  through a valve operation function. Valve control can be adjustable from fully open to fully closed and thus accommodate system operating parameters. The motor control  235  can likewise provide variable speed control, e.g., via a variable frequency/speed drive. Alternatively, a simplified motor control  234  can provide ON/OFF via digital contact control. 
       FIG.  10    shows projected well responses as a function of wellhead pressure, which can be determined at the pressure transducer  228 . The wellhead pressure responses change through pressure buildup, “burp,” pumping and pressure buildup from a surge due to well slugging. Limiting boundary conditions 1 and 2 are shown as pressure points for reference.  FIG.  11    shows states of control with respect to pump state, valve state, and motor control. 
     The control system  202  can be configured for further optimizing gas capture and thus minimizing or eliminating gas venting and flaring. The negative environmental impact of oil and gas production, and the corresponding “carbon footprint,” can likewise be reduced. For example, the harmonic signatures with various production and pressure buildup characteristics in determining the state of inflow performance while flowing and the pump state while pumping natural gas are controllable with the system  202 . Natural gas flaring and venting are functions of boundary conditions being exceeded. A first limiting boundary condition occurs when the sales gathering system  239  pressure exceeds wellhead pressure, measured at the transducer  228 . A second boundary limiting condition occurs when the wellhead pressure at the transducer  228  exceeds the value allowed by the gathering system  239 . The gathering system pressure values, and the corresponding limits, are numerical inputs to the controller, either the local controller  204  at the well, or to the cloud for computational analysis at  206 . The control valve  226  and the pump motor control  235  can be interactively controlled and adjusted to achieve and maintain optimal operating conditions. The control system  202  records and accurately predicts pressure buildup as a function of time from historical data limiting the pressure overshoot as one of the functions of the machine learning software. 
     VII. Conclusion 
     It is to be understood that while certain embodiments and/or aspects of the invention have been shown and described, the invention is not limited thereto and encompasses various other embodiments and aspects.