CROSS-REFERENCE TO RELATED APPLICATION [0001] This application is related to U.S. Non- Pro visional Patent Application No.

16/110,945, filed August 23, 2018, which is a non-provisional of U.S. Provisional Patent Application No. 62/549,036 Filed August 23, 2017, both of which are incorporated herein by reference.

BACKGROUND OF THE INVENTION

1. Field of the Invention

[001] The present invention relates generally to improving currently-used artificial lift methods for the production of oil, natural gas and water from vertical and horizontal wells, 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, and less-frequent pump failures. This benefits operating costs, future capital costs, and in certain cases revenue due to an increase in recoverable reserves at the well and field level.

2. Description of the Related Art.

[002] 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.

[003] Another production method sometimes used involves incorporating what is known as a “Pump Off Controller” (POC) procedure, which attempts to maximize the pumping- efficiency system, but not necessarily the well production, 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.

[004] 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.

BRIEF SUMMARY OF THE INVENTION

[005] The present invention generally provides a novel system and method for using data acquired at the well by gas metering and understanding 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, and optimizing the entire gathering system when used on a field- wide application. This system will optimize both well reservoir performance in addition to pumping system performance. This is different from POC systems which, in essence, are attempting to optimize the pumping system but not the actual well production.

BRIEF DESCRIPTION OF THE DRAWINGS [006] The drawings constitute a part of this specification and include exemplary embodiments of the present invention illustrating various objects and features thereof.

[007] Fig.l is a schematic, block diagram of an oil and gas production well system embodying an aspect of the present invention.

[008] Fig. 2 is a fragmentary, elevational view of an oil and gas production wellstring for producing liquids via a pump within a tubing string and producing natural gas via a backside of the well, with portions broken away to reveal internal construction.

[009] Figs. 3a-3c show a flowchart of a method of the present invention.

[0010] 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.

[0011] Figs. 5a-5c show a flowchart of a modified or alternative embodiment method of the present invention.

[0012] Figs. 6a-6c show a simple digital (on/off) control scheme for use with the system and method of the present invention. [0013] Figs. 7a-7c show a complex (variable) control scheme for use with the system and method of the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

I. Introduction and Environment

[0014] 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.

[0015] 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

[0016] 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.

[0017] The system 2 includes a wellstring 8 (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. Patent No. 7,090,027 shows casing hanger assemblies, and is incorporated herein by reference. The wellstring 8 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 8 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.

[0018] 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.

[0019] 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.

[0020] 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.

[0021] 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.

[0022] The system 2 uses instantaneous PDIFF 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 PDIFF 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. [0023] 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’ PDIEF. 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 PDIEF 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 PDIEF until the logic determines a necessity to close the control valve 26 and begin a pumping condition cycle.

[0024] When the controller 4 initiates the pumping condition, the control valve 26 is automatically closed, halting fluid upflow in the first backside 18 (VUPFLOW = 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.

[0025] 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 PDIEF 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.

[0026] 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.

[0027] The cloud 6 can incorporate machine learning techniques to optimize the well production as a function of ran 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 PDIEF, 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 leam 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.

[0028] 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. Methods Embodying Aspects of the Invention

[0029] Figs. 3a-3c 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 Modified or Alternative Aspects of the Invention

[0030] Fig. 4 shows an oil and gas production well control system 102 comprising a modified or alternative embodiment of the present invention and including a production well

103 with 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.

[0031] The well 103 includes a conventional wellstring, which is similar to the wellstring 8 shown in Fig. 2. Multiple production wells 103 can be included in the system and driven by a single-point cloud/software system. The wellstring includes an outermost casing, an intermediate liner 12 and innermost, full-depth tubing 14. 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. Patent No. 7,090,027 shows casing hanger assemblies, and is incorporated herein by reference.

[0032] As shown in Fig. 2, 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. As shown in Fig. 4, a pump subsystem 135 includes a motor 132 and a pump motor control sensor 134. The pump subsystem motor 132 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.

[0033] 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 20 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. [0034] 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.

[0035] 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 (PDIFF) meter 142 to monitor and record the quantities of 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 (PDIFF) indicates flow rate. The instantaneous well gas production is directly proportional to the PDIFF recorded at the meter 142, which records both orifice plate 140 well side and gathering line measured pressures, the calculated PDIFF, 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. Wells with flaring systems would include a tee to the flare(s) between the separator 138 and the orifice plate 140 for the digital sales meter 142.

[0036] The production flow rate can be input to the local controller 104, if available, via a digital flow meter 142. Alternatively, PDIFF can be independently derived from the upstream and downstream pressure transducers 128, 130 if physical access to the gathering system (well) side of the orifice plate 140 is not possible. The transducer 130 can also be located on the operator side of the meter/orifice plate 140. In this respect the system 102 differs from the system 2 of the primary embodiment described above. It should be noted that if data from a flow meter is available to the system for PDIFF, 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 PDIFF 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.

[0037] The system 102 uses instantaneous PDIFF 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 18 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 PDIFF 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.

[0038] In a high gas-flow-rate condition via the second back side 20, the operating downhole pump subsystem 135 will intake gas as well as liquids during the pumping cycle.

In the same condition, a ‘high’ PDIFF 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 118. 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 PDIFF 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.

[0039] When the local controller 104 initiates the pumping condition, the control valve 126 is automatically closed, halting fluid upflow in the first backside 118 (VUPFLOW = 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.

[0040] 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 PDIFF 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 (18 and/or 20) of the well 103 as it changes state from flowing backside production to gravity segregation in the pumping cycle.

[0041] 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.

[0042] The cloud 106 can incorporate machine learning techniques to optimize the well production as a function of ran 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 PDIFF, 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 increasing both the life and 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 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 frac-production stages are contributing to wellbore fillage and production.

[0043] 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.

[0044] 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 gas. System 102 control capacity is dependent on well and gathering system restraints. However, the system 102 will inherently sense whether the well can or cannot flow gas into the gathering system. When the well pressure has decreased to the point where it can no longer flow into the gathering system, that gas typically goes to a well flare (or if not flared, vent) on location. The system can prevent or lessen the amount of flare gas by shutting the well in via control valve 126. The system 102 will then begin another well pressure build up cycle to ensure when valve 126 is opened on next cycle it will be at sufficient pressure to flow into the gathering system.

V. Methods Embodying Modified or Alternative Aspects of the Invention [0045] Figs. 5a-5c show a flowchart for a non-limiting, exemplary, modified or alternative method of practicing the present invention. Various other steps, sequences and operating parameters can utilize the inventive method.

[0046] Figs. 6a-6c shows a simple, digital (on/off) control scheme for the present invention with the controller 4/104 configured for receiving various operating parameter inputs and providing outputs including motor and valve operating signals. Sequential stage times are shown in a pressure vs. time graph for a repetitive cycle with a pressure build-up stage, a “burp” stage and a pump stage. Fig. 6 also shows the pump states (on and off) and the valve states (open and closed) in relation to the stage cycles.

[0047] Figs. 7a-7c shows a complex (variable) control scheme for the present invention, with a local controller 4/104 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 32/132. 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. 7b 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 4/104 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).

[0048] 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. [0049] 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.