Patent Publication Number: US-6705397-B2

Title: Liquid level detection for artificial lift system control

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of U.S. patent application Ser. No. 09/179,143, filed Oct. 26, 1998 now U.S. Pat. No. 6,516,879; which is a continuation of U.S. patent application Ser. No. 08/862,078, filed May 22, 1997, now U.S. Pat. No. 5,826,659 issued Oct. 27, 1998; which is a continuation of U.S. patent application Ser. No. 08/660,052, filed May 31, 1996, now U.S. Pat. No. 5,634,522 issued Jun. 3, 1997; which claims the benefit of U.S. Provisional Patent Application Ser. No. 60/006,164 filed Nov. 2, 1995. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates to producing wells having an artificial lift system for removing liquid from an underground formation. In one of its aspects, the invention relates to improved methods of and systems for control of artificial lift systems utilizing pressure measurements and pressure manipulation to detect the liquid level in the well bore to thereby increase the efficiency, operational predictability and to automate the artificial lift systems. In another of its aspects, the invention relates to the monitoring of production gas from a gas producing well and detection of the liquid level in the well bore to thereby control the artificial lift system to maximize gas production from the well while simultaneously maximizing artificial lift system performance and efficiency. 
     2. Description of Related Art 
     Artificial lift systems are commonly used to extract fluids, such as oil, water and natural gas, from underground geological formations. Oftentimes, the formations are more than 1,000 feet below the surface of the earth. The internal pressure of the geological formation is often insufficient to naturally raise commercial quantities of the liquid or gas from the formation through a bore hole. When the formation has a sufficient internal pressure to naturally lift the liquid from the formation, the natural pressure is often inadequate to produce the desired flow rate. Therefore, it is desirable to artificially lift the liquid from the formation by means of an artificial lift system. 
     Typically, the formation can comprise several separate layers containing the liquid and gas or can comprise a single large reservoir. A bore hole is drilled into the earth and passes through the different layers of the formation until the deepest layer is reached. Due to economic considerations, many bore holes extend only to the deepest part of the productive formation. In certain applications it is desired to extend the bore hole beyond the bottom of the productive formation. The portion of the bore hole that extends beyond the bottom of the formation and into the substrata is known as a “rat hole.” The location and depth of the bore hole is carefully controlled because of the great expense in drilling the bore hole. 
     After the bore hole is drilled, the bore hole is usually lined with a casing along its entire length to prevent collapse of the bore hole, to control reservoir pressure and to protect surface water from contamination. However, the bore hole is often only lined with the casing to the top of the gas and liquid containing formation, leaving the lower section of the bore hole uncased. The uncased section is referred to as an open hole. The casing is cemented in place and sealed at surface by a wellhead and can have one or more pipes, tubes or strings (metal rods) disposed therein and extending into the bore hole from the wellhead. One of the tubes is typically a production tube, which is used to carry liquid to the surface. 
     Currently, many different types of artificial lift systems are used to lift the liquid from the formation. The most common artificial lift systems are: progressive cavity pumps, beam pumps and subsurface gas lift (SSGL). A progressive cavity pump is relatively expensive, approximately $20,000 to install, but can deliver relatively large volumes of liquid and remove all the liquid from the formation. A progressive cavity pump can comprise an engine or electric motor driven hydraulic pump connected to a hydraulic motor mounted on the top of the wellhead and connected to a pump at the bottom of a production tube. The hydraulic motor turns a rod string that is connected to a pump rotor, which turns with respect to a pump stator. Alternately, some progressive cavity pumps are driven by an electric motor attached to the top of the well head. The pump rotor is helical in shape and forms a series of progressive cavities as it turns to lift or pump the liquid from the bottom of the well bore into the production tube and to the surface. Although the progressive cavity pump is satisfactory in raising liquid from the formation, the hydraulic pump system requires a containment building and liner in the event of an oil leak. The possibility of an oil leak in the progressive cavity pump system also raises environmental concerns because many of the bore holes are drilled in environmentally sensitive or wilderness areas. The progressive cavity pump also requires, in certain applications, at least 100 feet of a rat hole, which adds extra cost. Of the previously mentioned artificial lift systems, the progressive cavity pump has the highest maintenance costs and greatest amount of down time requiring rig service. This down time often results from a lack of good liquid level control which allows the well to be pumped off causing damage to the pump system. Also, a soft seal stuffing box which must be lubricated regularly is used to seal around the rotating rod string and acoustic annular liquid levels must be obtained at regular intervals to ensure that the liquid is adequately high above the pump so that it does not run dry and destroy itself. 
     A beam pump is also relatively expensive, approximately $18,000, to install but can also remove all the liquid from the formation. The beam pump comprises a pivotally mounted beam that is positioned over the wellhead and connected to a rod string extending into the production tube within the casing in the bore hole. The lower end of the rod string is connected to a pump disposed near the bottom of the well bore. The beam pump can be operated by a gas engine or an electric motor. The beam pump has several disadvantages. First, there are many environmental concerns. There may be leakage in the engine or gear box of the power source, requiring construction of a containment area. Further, if an electric motor is used in place of the gas engine, it is necessary to run a power line to the electric motor, which often destroys or degrades the surrounding environment. The beam pump, like the progressive cavity pump, has many moving components that require regular lubrication. The beam pump also uses a soft seal stuffing box to seal around the reciprocating rod string to contain liquids and gases produced up the production tube. 
     The SSGL is the least expensive artificial lift system to install, approximately $7,500. The SSGL uses pressurized gas carried by a separate tube, commonly referred to as a side string, from the surface to the lower end of the production tube to eject the liquid in the production tube to the surface upon injection of a blast of pressurized gas. The production tube usually has at its lower end a one-way valve called a “standing valve” which permits liquid standing in the formation to enter the production tube and rise in the production tube to the level of liquid in the formation. Often the SSGL system will have a plunger disposed within the production tube, but a plunger is an optional device to provide mechanical advantage for the blast of injection gas. 
     The SSGL is the most environmentally friendly, maintenance free and energy efficient of the three commonly used artificial lift systems. Unlike the other artificial lift systems, the subsurface gas lift system requires no systematic lubrication of the gas regulator and the motor valve. The SSGL maintains greater integrity of the well head in controlling the possibility of liquid leaks because the well head components are hard piped with no friction oriented soft seal such as is found in the stuffing boxes of the progressive cavity and beam pumps. The SSGL is virtually silent during operation and has very little surface equipment compared to a beam pump or progressive cavity pump. Therefore, it has less audible and visual impact on the surrounding environment. 
     The greatest disadvantage of the SSGL is that it becomes less efficient and more difficult to control as more and more liquid is removed from the formation. The SSGL can only raise the column of liquid in the production tube. The column of liquid in the production tube is equal to the level of liquid in the annulus and therefore the level of liquid in the formation if the production tube and annulus are equalized into a common line at surface. As more and more liquid is removed from the formation, the level of liquid in the formation decreases. Therefore, as the level of liquid in the production tube decreases and a continuously smaller and smaller amount of liquid is raised for substantially the same amount of energy. As the liquid level in the subsurface gas lift system decreases or the influx of liquid to the well bore becomes erratic, there becomes a point where it is no longer operationally predictable, safe or productive to use the subsurface gas lift system. Oftentimes, the subsurface gas lift system is operated as a crippled and inefficient system without a plunger or replaced with a beam pump and its accompanying undesirable attributes. Optionally, a “rat hole” can be bored with the bore hole in a subsurface gas lift system so that most of the liquid can be raised from the formation by placing the gas injection point below the level of the formation and in the rat hole. However, many bore holes were drilled without a rat hole before artificial lift became a generally accepted method of production and the cost associated with boring a rat hole is such that most companies still prefer to drill little, if any, rat hole. 
     Another disadvantage that is common to all artificial lift systems is that as the liquid level decreases or the influx of liquid to the well bore becomes erratic, the systems become operationally more difficult to efficiently control without damaging themselves regardless of the depth of the rat hole. In the event of no liquid level, the progressive cavity pump will quickly torque up and destroy the down hole pump, twist off the rod string or destroy the stator assembly. The beam pump will begin to pound as gas is drawn into the pump, the end result of which will be a scored or damaged pump barrel and eventually a parted rod string. The SSGL may “dry cycle,” a condition where the plunger arrives at the surface and bottom of the well with no liquid cushion and, therefore, possibly at a damaging velocity. As the level of liquid decreases in an SSGL system, there is an increased need to use the mechanical advantage provided by a plunger to optimize the use of injection gas. The installation of a plunger into a well bore that has a continually declining or erratic liquid level requires constant vigilance on the part of the system operator to reduce the volume of gas injected into the production tube to keep the plunger from developing higher and higher velocity as the liquid level decreases. If the SSGL injection is left without adjustment the plunger velocity often increases to a point where the lubricator and the standing valve will be damaged by plunger impact. 
     In summary, the damage to the progressive cavity and the beam pumps will require a work-over rig for repairs. The damage to the SSGL seldom requires more than a small wire line truck for a few hours to retrieve and repair the damaged components. However, each of these systems, if controlled improperly, can have catastrophic failures that can be physically dangerous to the operator, costly to repair and can inflict environmental damage. 
     Most production companies have a mix of all the lift system types throughout their fields and while SSGL is the most environmentally friendly and energy efficient, there are fields in which the beam pump and progressive cavity pump systems are used exclusively. For various reasons that include high rates of liquid production, easy access to electricity, lack of a pipeline distribution system to supply high pressure gas for a SSGL system, lack of compressor capacity to support SSGL systems or engineering preference, many wells use beam pumps, progressive cavity pumps and in some circumstances submersible electric pumps. All of these pumps will suffer damage if the liquid level in the well declines to a point where gas enters the pump or the well enters a pumped off condition. 
     There are various methods that can be used in conjunction with these pump systems to control pump off. In the case of a beam pump or progressive cavity pump, there are flow monitoring devices that can be installed in the liquid ejection line at surface to monitor the liquid flow to make sure it does not contain excessive quantities of gas or does not stop flowing. If an excessive quantity of gas or a no flow condition is detected, the pump will be shut down. In this method, a pump that is driven by an electric motor may be automatically shut down for a period of time and then restarted to pump until the well is pumped off again. A pump that is driven by a gas engine will be shut down and must be restarted by an operator. This method of pump off detection is inherently weak in that pump off is only detected after-the-fact. The influx of gas into the production tube can cause gas locking of the pump, excessive wear due to lack of liquids or excessive corrosion due to free gas in the production tube. Further, there is no provision for constant monitoring of the liquid level in the well bore to make sure the liquid has been reduced to a level below the productive formation. Therefore, acoustic annular liquid levels must be taken at regular intervals to optimize the performance and efficiency of the artificial lift system. 
     Another method of monitoring pump off in a system using an electricity driven submersible or progressive cavity pump is to monitor the current draw caused by the pump motor. In the case of the progressive cavity pump, if gas is being drawn into the pump, the current draw may increase because of increased friction, due to the lack of lubrication and cooling provided by the production liquids, which in turn causes the electric motor to work harder. In this method, the pump can be shut down for a period of time to allow liquid to enter the well bore before starting the pump again. However, this method of detection is also an after-the-fact detection of pump off and does not compensate for variations of liquid volume entering the well bore. In the case of the submersible electric pump the current draw may decrease as gas enters the pump due to the impellers spinning in a gaseous fluid. In this case, the system would be shut down to keep the pump from overheating due to lack of cooling liquids. Again, detection is after-the-fact and damage may be done to the pump. 
     In another prior art control system for the electric progressive cavity pump and the submersible electric pump system, the current load is monitored and this value is used to automatically adjust a variable speed drive on the electric motor. This control method resembles the use of a rheostat where power to the system is controlled to allow for speed adjustment of the electric motor and therefore speed adjustment of the pump. In this method, the motor speed is adjusted based on current load to control system pump off. However, adjustments are made in response to after-the-fact detection of pump off and the system is still unable to detect precise liquid levels in the well bore. 
     With the submersible electric pump, the progressive cavity pump and beam pump system, another inefficiency can develop if the well bore is configured with a deep rat hole. If the pump is placed substantially below the productive formation and into the rat hole and the liquid in the annulus is reduced down to the level of the pump, it will require significantly more energy to lift the liquid from the well bore than would be required if the liquid level in the annulus was up to the bottom of the productive formation or at the top of the rat hole. For example, if a well is 1000 feet deep to the base of the productive formation and has a 200 feet deep rat hole for a total well depth of 1200 feet, and the liquid being pumped has the density of fresh water with a pressure gradient of 0.433 psi per vertical foot, the head pressure of a liquid column inside the production tube at a depth of 1000 feet will be 433 psi and at a depth of 1200 feet the liquid head pressure will be 519.6 psi. In this scenario if a pump is set to a depth of 1200 feet (200′ into the rat hole below the productive formation) and the liquid level in the annulus is lowered to the level of the pump, the pump must overcome 1200 feet of hydrostatic head pressure or 519.6 psi to lift the liquid to the surface of the ground. Alternately, if the pump is set to a depth of 1200 feet but the liquid level in the annulus is maintained up to the bottom of the productive formation (200 feet above the pump in the annulus) the pump will only need to overcome 433 psi of hydrostatic head pressure to lift the liquid to the surface due to the equalizing force of the liquid in the annulus. In the scenario where the liquid level is reduced unnecessarily low in the annulus it will require approximately 20% more energy to lift a given volume of liquid to the surface than if the liquid level was maintained up to the bottom of the productive formation due to the lack of the balancing effect of the liquid in the annulus. 
     Therefore, there is a need to provide a method and system to conserve energy and increase longevity of the well bore equipment by precise control of the liquid level within the well bore to avoid pump off in artificial lift systems. A systemic method of control of the liquid level will improve the efficiency of the pump while further reducing the manpower requirements to operate the system by reducing the need for operator intervention with the artificial lift system to control liquid level to optimize well production and to prevent the system from damaging itself. There is further a need to have cost effective oil or gas well artificial lift systems that are relatively environmentally and operationally safe, low maintenance, operationally predictable, easy to use, have an acceptable level of efficiency and have the ability to automatically compensate to meet the variable conditions of a dynamic well bore. 
     SUMMARY OF INVENTION 
     The invention relates to a method and system of producing gas and liquid from a gas and liquid-containing underground stratum comprising a well bore extending between the surface of the ground to the stratum, the well bore having a casing and a production tube defining an annulus through which gas from the stratum passes and is collected at the surface of the ground through a production line. The production tube extends from the surface of the ground and is in fluid communication with the gas and liquid-containing stratum through which the liquid is collected from the well and removed to the surface by artificially raising the liquid in the production tube to the surface to thereby release gas from the formation to the well bore and production line. A side string tube extends from the surface of the ground through the annulus and is in fluid communication with the gas and liquid-containing stratum. An artificial lift system is provided for artificially raising the liquid in the production tube to the surface to thereby release gas from the formation to the well bore and production line. 
     According to the invention, a system for determining a liquid level of a column of liquid liquid exhibiting a predetermined pressure gradient contained in a well for controlling an artificial lift system for said well based on said liquid level of said column of liquid comprises introduction means for introducing a gas adjacent to a bottom of said column of liquid wherein the gas is introduced at a predetermined rate of flow so as to exhibit a predetermined negligible amount of pressure resistance due to frictional gas flow and sufficient to overcome a pressure exerted by said column of liquid adjacent to a bottom of said well. A sensing means is fluidly coupled to the introduction means for sensing a liquid column pressure at which said gas overcomes said pressure exerted by said column of liquid adjacent the bottom of said well. A processing means is responsive to said sensing means for determining the liquid level of said column of liquid from said pressure exerted by said column of liquid and said predetermined pressure gradient. 
     Further according to the invention, a system for determining a liquid level of a column of liquid having a predetermined pressure gradient in a well for controlling an artificial lift system for said well, based on said liquid level of said column of liquid, comprises an introduction means for introducing a gas adjacent to a bottom of said column of liquid, said gas being introduced at a predetermined rate of flow so as to exhibit a predetermined negligible amount of pressure resistance due to frictional gas flow and sufficient to overcome a hydrostatic pressure of the column of liquid adjacent a bottom of said well and sufficient to overcome a first pressure of gas in a space in the well above the column of liquid. A first sensing means is fluidly coupled to the introduction means for sensing a second pressure at which said gas overcomes the hydrostatic pressure of said column of liquid adjacent the bottom of said well and the first pressure. A second sensing means is coupled to the space in said well for sensing the first pressure in said space and a processing means is responsive to the first sensing means and said second sensing means for determining the liquid level based on the predetermined pressure gradient of the column of liquid and the difference between said hydrostatic pressure of said column of liquid and said first pressure. 
     In one embodiment, the liquid level is an annular liquid level inside said well. Preferably, the processing means determines said liquid level from dividing said liquid column pressure by said predetermined pressure gradient. 
     In a preferred embodiment, the processing means also controls a gas lift system fluidly coupled to said column of liquid in said well by controlling the injection rate of gas being introduced into said well based on comparing the determined liquid level against a predefined liquid level. Preferably, the processing means also controls said gas lift system intermittently through a timed relay connection to a motorized valve in the gas lift supply to said well. 
     In another embodiment, the processing means also controls the cycling of pumping units fluidly coupled to said column of liquid in said well, which remove the liquid in said well based on comparing the determined liquid level against a predefined liquid level. 
     In yet another embodiment, the processing means also controls a plunger lift system fluidly coupled to said column of fluid in said well for removing the liquid based on comparing the determined liquid level against a predefined liquid level. 
     In a preferred embodiment, the introduction means is a side string tube running from the surface to said bottom of the column of liquid so as to permit said gas to bubble up through said column of liquid when the pressure of said gas overcomes the pressure at said bottom of said column of liquid. Preferably, the sensing means is a pressure transducer converting the pressure sensed in said side string tube to electrical information transmitted to said processing means over a wired connection between said pressure transducer and said processing means. Further, the processing means is a programmable controller configured with software instructions for determining said liquid level and the processing means has knowledge of the predetermined pressure gradient of said column of liquid. 
     Still further according to the invention, a method for determining a liquid level of a column of liquid having a predetermined pressure gradient in a well for controlling an artificial lift system for said well, based on said liquid level of said column of liquid, comprises the steps of introducing a gas adjacent to a bottom of said column of liquid at a predetermined rate of flow so as to exhibit a predetermined negligible amount of pressure resistance due to frictional gas flow and sufficient to overcome a hydrostatic pressure of said column of liquid adjacent a bottom of said well as well as a first pressure of any gas in a space in the well above the column of liquid; sensing through a fluid coupling a second pressure at which said gas overcomes said hydrostatic pressure and said first pressure; sensing through another fluid coupling the first pressure; and determining said liquid level based on said predetermined pressure gradient and the difference between said second pressure and said first pressure. 
     In one embodiment, the liquid level is an annular liquid level in said well. Preferably, the liquid level is determined by dividing the difference between said second pressure and said first pressure by the predetermined pressure gradient. 
     In another embodiment, the invention further comprises the step of controlling a gas lift system in said well by controlling the injection rate of gas being introduced into said well based on comparing the determined liquid level against a predefined liquid level. Preferably, the gas lift system is controlled intermittently through a timed relay connection to a motorized valve in a gas supply to the gas lift system in said well. 
     In yet another embodiment, the cycling of pumping units for removing the column of liquid in said well is controlled based on comparing the determined liquid level against a predefined liquid level. 
     In yet another embodiment, a plunger lift system in said well for removing the column of liquid is controlled based on comparing the determined liquid level against a predefined liquid level. 
     In yet another embodiment, the step of introducing a gas to the bottom of said column of liquid is through a side string line extending from the surface to said bottom of the column of liquid so that the gas bubbles up through the column of liquid when the pressure of the gas overcomes the pressure at said bottom of the column of liquid. 
     In the embodiment of the invention wherein the artificial lift system comprises a gas injection system with an injection valve for periodically injecting a blast of gas into a lower portion of the production tube through the side string tube, the controller is operably connected to the injection valve and is adapted to control the initiation of the blast of gas into the production tube to artificially lift the liquid in the production tube to the surface of the ground. The controller actuates the injection valve to initiate the injection of gas into the side string tube when the measured level of liquid in the production tube reaches a predetermined value representative of the desired level of liquid in the production tube and well bore. Preferably, the controller is adapted to compute the level of liquid in the production tube in response to the first pressure signal after liquid has been substantially cleared from the side string tube by the injection of a minuscule volume of gas. 
     In a preferred embodiment of the invention wherein the artificial lift system comprises a gas injection system, a second pressure sensor is fluidly attached to the production tube to sense the pressure therein and to generate a second pressure signal representative of the pressure in the production tube. A controller is operably coupled to the second pressure sensor and is adapted to compute the level of liquid in the production tube in response at least in part to the first and second pressure signals. In a preferred embodiment of the invention, the controller is adapted to compute the level of liquid in the production tube in response to the difference between the first and second pressure signals. 
     In another embodiment of the invention, the artificial lift system comprises a beam pump. In still another embodiment of the invention, the artificial gas lift system comprises a progressive cavity pump. In still another embodiment of the invention, the artificial lift system is an electrically driven submersible pump. 
     In a preferred embodiment of the invention wherein the artificial lift system incorporates a pump, a second pressure sensor is fluidly attached to the annulus to sense the pressure therein and to generate a second pressure signal representative of the pressure in the annulus. A controller is operably coupled to the second pressure sensor and is adapted to compute the level of liquid in the well bore in response at least in part to the first and second pressure signals. 
     According to one aspect of the invention, the controller is adapted to compute the level of liquid in the well bore in response to the difference between the first and second pressure signals. Preferably the controller is adapted to generate an output signal for controlling the initiation of the artificial lift system when the liquid level in the well bore as detected by pressure reaches a predetermined value. 
     The invention can be applied to a single producing well with the controller physically at the wellhead. Alternatively, a controller can be used to control a plurality of wells. The controller can be located geographically remote from each of the wells and in communication with the sensors and control valves at the well head through electrical communication lines or through telemetry. 
     The invention also contemplates several variations of pressure monitoring for control of the artificial lift systems in wells using the beam pump, progressive cavity pump or the electric submersible pump methods of artificial lift, each with the objective of detecting the level of liquid in the well bore prior to making adjustments to the artificial lift system. These methods have varying accuracy according to the operational need dictated by the well bore configuration. In one embodiment of the invention, operational efficiency and control is enhanced by volumetric measurement of production gas to control the operation of the artificial lift system by automated control of the liquid level in the well bore. 
     Fundamental to an understanding of how the pressure monitoring and control system of the invention can have a positive impact on artificial lift system performance is an understanding of the variations in pressures that can and do exist at various points in the artificial lift system. These pressures, measured at the appropriate time and interpreted correctly, will give a very accurate determination of the liquid level in the production tube and/or well bore. 
     Pressures in a bore hole are commonly referred to in the terms of pressure gradients. “Gradient” is defined as psi per vertical foot in the bore hole. Fresh water will have a gradient of 0.433 psi per vertical foot, whereas low pressure gas gradient may be as minimal as 0.002 psi per vertical foot. In effect, a 1000′ column of fresh water will have a bottom hole or head pressure of 433 psi whereas the low pressure gas will have a bottom hole or head pressure of 2 psi. 
     In a well using the subsurface gas lift (SSGL) method of artificial lift, subsequent to the injection portion of the SSGL cycle, liquid will enter the bottom of the production tube through the standing valve attached to the injection mandrel and displace the gas in the production tube into the ejection line and to the collector at surface until the well bore has achieved static equilibrium. (Static equilibrium is commonly defined as the time when head pressure at the injection mandrel is substantially equalized between the inside of the production tube and the annular section of the well bore. Therefore, a no-flow condition exists between production tube and the annulus.) The column of liquid entering the production tube and displacing the gas into the flow line at surface will at the same time try to enter into the side string tube attached to the injection mandrel above the standing valve. However, the side string tube, unlike the production tube, is closed at surface. Therefore, the liquid can only enter the side string tube until the cumulative head pressure of the gas and liquid in the side string tube at the injection mandrel is equal to the cumulative head pressure of the gas and liquid in the production tube at the injection mandrel. At this point, the difference between the side string injection line pressure at surface and the production tube pressure at surface multiplied by the appropriate liquid gradient pressure factor will give the approximate liquid level in the production tube. The reason the liquid level is only approximate is due to the fact that liquid has entered the side string tube to compress the gas in the side string tube which causes there to be two different gradients in the side string tube, one for gas and one for liquid, the level of which is unknown. At this point, pressure manipulation will accurately determine actual liquid level in the production tube. Manipulation is accomplished by the injection of a minuscule volume of gas into the side string injection line attached to the side string tube. This volume will displace the liquid in the side string tube, causing only gas to be present in the side string tube. This volume is estimated based on the diameter of the side string tube and the estimated height of liquid in the side string tube. Typically, the amount of gas is determined by monitoring the pressure in the side string injection line at surface as the gas is injected into the side string tube and the volume is typically very small as compared to the amount of gas injected during the SSGL injection cycle. The pressure in the side string injection line will increase as the minuscule volume of gas is injected into the side string tube until all of the liquid in the side string tube is forced into the production tube at which time the pressure will stabilize. This step can be carried out manually by an operator or automatically by a controller. As a practical matter, the minuscule volume of gas can be injected continuously between injection cycles to maintain the side string tube free of liquid. As a result, the difference between the pressures in the side string injection line at surface and the production tube at surface multiplied by the appropriate liquid gradient factor is used to compute the level of liquid in the production tube with great accuracy. The computations are done reiteratively until the computed level of liquid in the production tube is equal to a predetermined level which is based on the well bore characteristics. When the predetermined level and the computed levels are equal, the SSGL injection cycle can then be initiated by the controller if desirable. This known level of liquid in the production tube can thus be used to greatly improve the efficiency of the SSGL system by effecting the cycling only when an optimum liquid level has been achieved while eliminating the single greatest control problem for SSGL, the “destructive dry cycle” that often causes mechanical damage and can cause environmental damage. 
     The invention uses variations of a method of liquid level detection to provide improved control methods and apparatus for various types of gas or oil well artificial lift systems which enhance efficiency, improve production, are cost effective, environmentally friendly, contribute to operational predictability and safety, are diverse enough to accommodate various well bore configurations, and are able to automatically accommodate a dynamic well bore and support the prudent and timely use of energy resources. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     The invention will now be described with reference to the drawings in which: 
     FIG. 1 is a schematic cross sectional view of a bore hole with a subsurface gas lift artificial lift system incorporating a control system according to the invention; 
     FIG. 2 is a schematic cross sectional view of an alternate bore hole which can be used with an SSGL artificial lift system according to the invention; 
     FIG. 3 is a schematic cross sectional view of an alternate bore hole which can be used with an SSGL artificial lift system according to the invention; 
     FIG. 4 is a schematic representation of an alternate well head assembly which can be used with an SSGL artificial lift system incorporating a control system according to the invention; 
     FIG. 5 is a schematic representation of a second alternate well head assembly which can be used with an SSGL artificial lift system incorporating a control system according to the invention; 
     FIG. 6 is a block diagram illustrating a method according to the invention for controlling a gas injection cycle in an oil or gas well having an SSGL artificial gas lift system; 
     FIG. 7 is a block diagram illustrating yet another method according to the invention for controlling a gas injection cycle in an oil or gas well having an SSGL artificial gas lift system; 
     FIG. 8 is a block diagram illustrating still another method according to the invention for controlling a gas injection cycle in an oil or gas well having an SSGL artificial gas lift system; 
     FIG. 9 is a block diagram illustrating still another method according to the invention for controlling a gas injection cycle in an oil or gas well having an SSGL artificial gas lift system; 
     FIG. 10 is a block diagram illustrating a method according to the invention for dynamically adjusting a predetermined artificial lift liquid level set point in an oil or gas well having an artificial lift system; 
     FIG. 11 is a block diagram illustrating a method according to the invention for dynamically controlling the necessary volume of gas injected during a gas injection cycle in an oil or gas well having an SSGL artificial gas lift system; 
     FIG. 12 is a block diagram illustrating another method according to the invention for dynamically controlling the necessary volume of gas injected during a gas injection cycle in an oil or gas well having an SSGL artificial gas lift system; 
     FIG. 13 is an enlarged cross sectional view of a modified lubricator for detecting liquid arrival according to the invention; 
     FIG. 14 is a diagrammatic representation of a plurality of well systems arranged for telemetric communication between a remote computer which can be used for control in any of the methods or systems according to the invention; 
     FIG. 15 is a schematic cross sectional view of a beam pump artificial lift system and bore hole with a control system according to the invention; 
     FIG. 16 is a schematic cross sectional view of a progressive cavity pump artificial lift system and bore hole with a control system according to the invention; 
     FIG. 17 is a schematic cross sectional view of an alternate bore hole which can be used with a beam pump or progressive cavity pump artificial lift system according to the invention; 
     FIG. 18 is a schematic cross sectional view of an alternate bore hole which can be used with a beam pump or progressive cavity pump artificial lift system according to the invention; 
     FIG. 19 is a schematic representation of an alternate well head assembly which can be used with a beam pump or progressive cavity pump artificial lift system incorporating a control system according to the invention; 
     FIG. 20 is a schematic cross sectional view of a submersible pump artificial lift system and bore hole with a control system according to the invention; 
     FIG. 21 is a schematic cross sectional view of an alternate bore hole which can be used with a submersible pump artificial lift system according to the invention; 
     FIG. 22 is a schematic cross sectional view of an alternate bore hole which can be used with a submersible pump artificial lift system according to the invention; 
     FIG. 23 is a schematic representation of an alternate well head assembly which can be used with a submersible pump artificial lift system incorporating a control system according to the invention; 
     FIG. 24 is a block diagram illustrating a method according to the invention for controlling a pump in an oil or gas well having an artificial lift system; 
     FIG. 25 is a block diagram illustrating yet another method according to the invention for controlling a pump in an oil or gas well having an artificial lift system; 
     FIG. 26 is a block diagram illustrating still another method according to the invention for controlling a pump in an oil or gas well having an artificial lift system; 
     FIG. 27 is a block diagram illustrating and still another method according to the invention for controlling a pump in an oil or gas well having an artificial lift system; and 
     FIG. 28 is a block diagram illustrating a method according the invention for dynamically adjusting a predetermined set point to reduce energy drawn by the artificial lift system during peak load hours and optimize production. 
    
    
     DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     To avoid an unreasonable amount of redundance, the invention will be described in two parts. 
     In part one, as the invention applies to an artificial lift system incorporating sub surface gas lift SSGL (FIGS.  1  through  14 ), and in part two, as the invention applies to artificial lift systems incorporating the use of a pump (FIGS. 10, and  15  through  28 ). In each of these artificial lift systems the invention will be describe from its most simple form using only one sensor  92  to a complete system that is both dynamic and interactive using multiple sensors  91 ,  92 ,  93 ,  94  and in the case of the SSGL system including the use of a magnetic sensor  95 . 
     In part one, FIG. 1 illustrates a well assembly having an artificial lift system  10  that incorporates a subsurface gas lift system (SSGL) and an electronic controller  90  in conjunction with electronic sensors  91 ,  92 ,  93 ,  94 , and  95 . The controller  90  can be one of any well known micro controllers having a central processing unit, arithmetic logic unit, memory locations, input/output ports, timer(s), etc, or can be an electronic circuit having a comparator depending on the particular well assembly complexity. The comparator can also be associated with a display, such as a monitor or printer for displaying well conditions. The system is closed to atmosphere, creating a closed artificial lift system. 
     As illustrated, the formation contains two types of fluid, natural gas  30  and water  32  in the liquid state. However, other types of liquid such as liquid hydrocarbons can be in the formation  51 . The natural gas  30  and liquid  32  are typically separated because of their different densities. The liquid  32  can have some natural gas in solution. The formation  51  can also hold substantial quantities of natural gas that is retained within the formation  51 . The natural gas  30  and liquid  32  are usually under pressure in the formation  51 . The pressure of the fluids in the formation can be caused by the weight of overburden  50  acting on the formation and the pressure of the liquids in the formation  51 . This internal pressure of the formation is known as the head pressure. The natural gas  30  and liquid  32  are at static equilibrium within the formation  51 . To deplete the natural gas from the formation  51 , it is necessary to remove the liquid from the formation  51  so that the head pressure is reduced to release the natural gas  30  from the formation  51  and so the natural gas  30  in the formation  51  can fill the well bore in the area vacated by the removed liquid  32 . 
     The well assembly  60  comprises a casing  42  disposed from the surface and extending into the bore hole  43  and into the formation  51 . Preferably, the casing  42  extends substantially to the bottom of the overburden  50  and to the formation  51  and is open at the lower end or has suitable perforations through which the gas  30  and liquids  32  can pass. However, a rat hole portion  45  of the bore hole, shown in FIGS. 2 and 3, can be drilled below the bottom of the formation  51  and into the substrata  52  and the casing  42  can extend into the rat hole  45 . 
     The casing  42  is sealed with respect to the atmosphere at its upper end by a wellhead  60 . A production tube  41  extends through the wellhead  60  and extends substantially near the bottom of the bore hole  43 . The casing  42  may or may not extend to the bottom of the formation, depending on the application. Although the casing  42  is illustrated as extending the entire length of the bore hole, (FIGS.  2  and  3 ), the casing  42  typically extends only to a depth dictated by engineering preference or completion technique because of the relatively high cost of installing and perforating the casing  42 . However, the casing  42  is present at the surface of the bore hole and cooperates with the wellhead  60  to seal the bore hole with respect to the atmosphere. 
     An annulus  46  is formed by the inner diameter of the casing  42  or bore hole  43  and the outer diameter of the production tube  41 . The lower end of the production tube  41  has an injection mandrel  80  in which is mounted a one-way standing valve  81 . A high pressure side string injection line  24  extends from a high pressure gas source  20  through the well head  60  to a high pressure side string injection tube  40  and to the injection mandrel  80 . Preferably, the side string injection tube  40  is fluidly connected with the I.D. of injection mandrel  80  above the standing valve  81 . When high pressure gas is directed from the high pressure gas source  20  through the side string injection tube  40  and into the production tube  41 , the standing valve  81  prohibits the high pressure gas from escaping from the production tube  41  and keeps the high pressure gas out of the annulus  46 . A plunger  82  can be disposed in the production tube  41  above the inlet for the side string injection tube  40  and is sized to fit within close tolerance of the inner diameter of the production tube  41 . In some SSGL systems, the plunger is eliminated. 
     An open hole or uncased section of the bore hole  43  (FIG. 1) or a series of perforations  44  (FIGS. 2 and 3) are formed in the casing so that the fluids, such as the natural gas and liquid, can enter the annulus  46 . The casing  42  also has a production line  77  positioned at the surface, and extending to a collector  100  which separates liquid from gas, so that the natural gas entering the annulus  46  through the perforations  44  or open hole  43  can be directed to the collector  100 . A valve  70  and a check valve  71  are disposed within the production line  77  between the casing  42  and the collector  100 . The valve  70  and the check valve  71  control the flow of natural gas  30  from the annulus  46  to the collector  100 . Preferably, the valve  70  is a manually operated valve to close the production line  77 , whereas the check valve  71  is a one-way valve that permits the flow of the natural gas  30  from the annulus  46  to the collector  100  but prohibits flow from the collector  100  into the annulus  46 . The production line  77  further has in it a measurement orifice  76  and pressure sensors and transmitters  93  and  94 . The measurement orifice  76  is operably connected to the differential pressure transmitter  93  and pressure transmitter  94  is operably connected to the production line  77 . (While only a single method of gas measurement is presented herein it is to be understood that any method of gas measurement such as a turbine meter or vortex meter, etc. may be used as long as an output signal is generated representative of the flow in the production line  77 .) The collector  100  is further connected to the production tube  41  through master valve  61 , lubricator  62 , ejection line  74  and commingling line  75 . The ejection line  74  has a pressure sensor and transmitter  91 , and isolation valve  72  and a check valve  73 . 
     A motor valve  21 , pressure sensor and transmitter  92  and a valve  22  are positioned in the side string injection line  24 . The valve  22  is preferably a manually operated valve for opening and closing the side string injection tube  40  when desired. The motor valve  21  is connected to a controller  90  having a timer. A small branch line  36  extends from the high pressure source  20  to the side string injection line  24  between the motor valve  21  and the pressure sensor and transmitter  92 . The branch line  36  has a regulator  23  to control the pressure and volume flowing therethrough. The controller  90  can be programmable and opens and closes the motor valve  21  so that the high pressure gas from the high pressure gas source  20  can be injected through the side string tube  40  and into the production tube  41  at either predetermined or dynamic intervals according to the invention. The controller  90  can be any suitable controller which is programmable to make the computations from the pressure signals from the sensors  91 ,  92 ,  93 ,  94  and  95 , compare the resultant signals to predetermined set points, and open the valve  21  for a predetermined length of time during the SSGL cycle. The controller  90  is further programmable to make the computations described hereinafter for adjusting the time of the gas injection cycle and to adjust the predetermined set points on the controller as described hereinafter. A suitable controller for this purpose is a Pumpmate Control, sold by OKC Products of Longmont, Colo. Further the controller  90  can be a simple monitoring device incorporating a timer and a telemetry unit  290  (FIG. 14) that transmits the value from the sensors  91 ,  92 ,  93 ,  94  and  95  to a remote data receiver  292  and computer  294  which completes the logic functions and then transmits the control parameters according to the invention back to the telemetry unit  292  and to the timer  90  for control of the artificial lift system  10 . 
     A lubricator  62  is mounted to the wellhead  60  above the production tube  41  and is fluidly connected to the production tube  41 . The lubricator  62  is an extension of the production tube  41 . The lubricator preferably has a cushioning device, such as a spring, positioned at the upper end of the lubricator  62  when a plunger  82  is disposed in the production tube  41 . The spring functions to cushion or arrest the upward movement of the plunger  82 . The lubricator  62  can consist of any device with an outlet to the ejection line  74  if a plunger  82  is not disposed in the production tube  41 . A valve  61  is connected to the production tube  41  at an upper portion thereof and is preferably manually operated to open and close the flow from the production tube  41  and through the lubricator  62  when desired. 
     An ejection line  74  extends from the lubricator  62 , preferably above the valve  61 , and is connected to the production line  77 . Alternately, according to FIGS. 4 and 5, the ejection line  74  can be isolated from the production line  77  or intermittently equalized with the production line  77 . Preferably a valve  72  and a check valve  73  are connected in the ejection line  74 . The pressure sensor and transmitter  91  is also mounted in the ejection line  74  to detect the pressure in the production tube  41  at the surface of the ground. The valve  72  is a manually operated valve to open and close the ejection line  74 , whereas the check valve  73  is preferably a one-way valve for controlling the flow from the lubricator  62  to the production line  77 , but preventing flow from the production line  77  to the ejection line  74  and into the production tube  41 . The check valves  71  and  73  keep fluids from back flowing from the commingling line  75  into the production tube  41  or the annulus  46 . 
     The check valves  71  and  73  isolate the annulus  46  and the production tube  41  from back flowing into each other at the surface but allow them to equalize in pressure with respect to the commingling line  75 . Because the production tube  41  and the annulus  46  are fluidly connected to commingling line  75 , they are equalized in pressure at surface and the liquid can reach a static equilibrium with similar levels in the production tube  41  and the annulus  46 . Alternately, the ejection line  74  and the production line  77  can be isolated to their respective collectors (FIG.  4 ), and, therefore, static equilibrium can be achieved with dissimilar liquid levels in the production tube  41  and the annulus  46 . During the injection of high pressure gas from the high-pressure gas source  20  through the side string injection line  24  down the side string injection tube  40  and the ejection of liquids up the production tube  41  through the ejection line  74  and into the commingling line  75 , the check valve  71  directs the liquid flow to the collector  100  rather than allowing the liquid to reenter the annulus  46 . 
     Although only one plumbing arrangement is shown in FIG. 1, there are many possible variations. It should be understood that the well assembly  60  and the SSGL  10  can be reconfigured so as to eliminate or include various components as long as sensors  91  and  92  are mounted in the injection line  24  and the ejection line  74 , respectively, to gather pressure information to determine the static liquid level  34  within the production tube  41 . Sensors  93  and  94  are mounted in gas production line  77  to gather pressure information to determine production through the production line  77  and sensor  95  is mounted to the lubricator  62  or to the upper portion of the production tube  41  to detect the plunger  82  or liquid  32  travel time to surface. Further, even though the pressure sensors and transmitters  91 ,  92 ,  93 ,  94  are shown in only one configuration, various arrangements can be used. For example in FIG. 1, pressure sensor  94  could serve the dual purpose of pressure measurement of the production line  77  and ejection line  74  because these lines are substantially equalized. Therefore many possible plumbing and electronic arrangements exist within the scope of the invention without departing from the spirit of the invention. 
     There are several pressure measurements relevant to determining the bottom hole or head pressure in the artificial lift system  10  and the location of the liquid level  34  in the production tube  41  and therefore the annulus  46 . Besides the pressure of the side string injection line  24  at surface and the production tube  41  at surface, the pressures in the length of bore hole  43  and the production tube  41  must also be considered. The pressures in the length of bore hole  43  and the production tube  41  are commonly referred to in the terms of pressure gradients. “Gradient” is defined as pounds of pressure per square inch (psi) per vertical foot in the bore hole. For example, fresh water will have gradient of 0.433 psi per vertical foot, whereas an unpressurized gas gradient may be as low as 0.002 psi per vertical foot. In effect, a 1000-foot column of fresh water will have a bottom hole or head pressure of 433 psi whereas a 1000-foot column of unpressurized gas would have a bottom hole or head pressure of 2 psi. 
     Most artificial lift systems discharge their liquids or gas into a pressurized production line  77 , such as a pipeline system that directs the liquids or gas to a collector, such as collector  100  at a production facility. This gathering system pressure promotes flow from the well head to the production facility and also aids in the separation of the gas and liquid in that the collector  100  may require pressure to discharge the liquid from the collector  100  to a tank. Also, the compressors used to compress the gas up to sales line pressure, except in rare configurations, require a positive inlet pressure to perform efficiently. Variations in this pipeline pressure and, therefore, the production line  77  pressure will cause the SSGL artificial lift system  10  to perform erratically in that higher pressures often cause the static liquid level  31  in the annulus  46  to decrease. Decreasing the liquid level in the annulus  46  will decrease the liquid level in the production tube  41 . Without a corresponding decrease in the volume of injection gas  20  injected into the production tube  41 , the plunger  82  will rise in the production tube  41  with ever increasing velocity. If this condition is unchecked, damage may result. On the other hand, a decreasing pressure on the pipeline system and, therefore, in the production line  77  will cause the static liquid level  31  in the annulus  46  to rise. A rising static liquid level  31  in the annulus  46  will cause the liquid level  34  in the production tube  41  to rise. An increase in the liquid level in the production tube  41  without a corresponding increase in the volume of injection gas  20  injected into the production tube  41  under the plunger  82  will cause the plunger to fail to rise to surface and eject the liquid. If this condition is unchecked, the well will load up with liquid and gas production  30  into the annulus  46  will become suppressed. Therefore, a method of detecting the static liquid level  31  in the well bore to initiate the artificial lift  10  cycle and automatically adjusting the injection gas  20  volumes injected into the production tube  41  to sustain a consistent production gas  30  volume in a system with ever changing pressures and liquid level is of great importance. 
     Referring to FIG. 1, the operation of the SSGL artificial lift system  10  begins with the opening of valves  22 ,  61 ,  70 , and  72 . Valves  22 ,  61 ,  70 , and  72  are normally open during normal production operations. The liquid  32  in the formation  51  can then more fully enter the production tube  41  through the standing valve  81  attached to the injection mandrel  80  to reach a point of static equilibrium with the liquid level  31  in the formation  51  because the production tube  41  is fluidly equalized at the surface with the annulus  46  via the production line  77 , the ejection line  74  and the commingling line  75 . The controller  90  initiates the injection of gas into the side string  40  and into the mandrel  80  under the plunger  82  by opening the motor valve  21  to physically raise the liquid  32  in the production tube  41  to the surface and remove the liquid  32  through the lubricator  62  into the ejection line  74  and to the collector  100 . After a predetermined and arbitrary period of injection into the side string tube  40 , the controller  90  will close the motor valve  21  until the next injection cycle is to begin. The blast of injection gas from source  20  is prohibited from exiting the bottom of the production tube  41  by the one way standing valve  81  which allows the liquid  32  to enter the production tube  41  but prohibits the liquid  32  and the injection gas in the production tube  41  from escaping into the annulus  46 . Further, the check valve  71  on the production line  77  directs the flow of liquid  32  and injection gas from the ejection line  74  down the commingling line  75  to the collector  100  and prohibits the back flow of liquid  32  or injection gas  20  into the annulus  46 . 
     A pressure sensor  92  is fluidly connected to the side string injection line  24  to detect the pressure caused by the influx of liquid  32  into the production tube  41 . The liquid  32  entering the production tube  41  will rise to a point  34  where the combined head pressure of the gas and liquid in the production tube  41  will be equal to the combined head pressure of the gas and liquid in the annulus  46  at the injection mandrel  80 . As the liquid  32  enters the production tube  41 , it will also enter the side string tube  40  through the side string tube  40  attachment port on the mandrel  80 . However, the side string tube  40  influx liquid  33  entering into the side string tube  40  will achieve only a portion of the liquid level  34  in the production tube  41  because the side string injection line  24  motor valve  21  is shut and the side string tube  40  is not equalized with the production line  77  or ejection line  74  at surface. This influx of liquid  33  will cause the pressure of the side string injection line  24  at surface to rise until the combined head pressures of the gas in the side string tube  40  and the liquid level  33  in the side string tube  40  are equal to the combined head pressure of the gas and liquid in the production tube  41  at the side string tube  40  attachment point on the mandrel  80 . At this point, the difference between the side string injection line  24  pressure at surface and the production tube  41  pressure at surface multiplied by the appropriate liquid gradient pressure factor will give an approximate liquid level  34  in the production tube  41 . It is important to understand, however, that the liquid level is approximate due to the fact that liquid has entered the side string tube  40  to compress the gas in the upper portion thereof which results in two different gradients in the side string tube  40 , one for gas and one for influx liquid  33 , the level of which is unknown. This side string injection line  24  pressure detected by pressure sensor  92  can be used to determine an estimated pressure set point to be programmed into the controller  90  to initiate the SSGL injection cycle based on an estimated liquid level. To this end, the pressure sensor  92  is electrically connected to the controller  90  so that a signal representative of the pressure in the side string line  24  as detected by the pressure sensor  92  is input into the controller  90 . The controller is programmed with a predetermined set point representative of the desired liquid level in the production tube  41  for initiation of the SSGL injection cycle. 
     The basic method of controlling the SSGL cycle, as shown in FIG. 6, includes reiteratively monitoring the production tube liquid level throughout the SSGL non-injection or off cycle by detecting the side string tube (sst) pressure with pressure sensor  92  as represented in block  210 . The controller  90  then compares the detected side string pressure to the predetermined set point as represented at block  212 . If the side string pressure is less than the predetermined set point, the side string pressure is again detected. When the production tube  41  liquid level  34  (as indicated by pressure) substantially equals the predetermined set point in the controller  90 , controller  90  will initiate the SSGL injection cycle as represented at block  214 . In this step, the controller  90  will open control valve  21  for a predetermined period of time to deliver a high-pressure blast of gas to the bottom of the production tube  41 . During initiation of the SSGL injection cycle, a time delay as represented at block  216  is activated. This time delay allows the liquid column and/or plunger  82  to reach the surface and also allows the plunger  82  to return under gravity to its position proximal to the side string injection tube  40  inlet to the injection mandrel  80  before commencing another reiterative monitoring of the production tube  41  liquid level  34 . 
     This method will require the greatest amount of operator intervention to work with nominal efficiency. This method will only give a rough estimate of the liquid level  34  in the production tube  41  due to the fact that there will be an influx of liquid  32  into the side string  40  the level  33  of which unknown. This method is also prone to error in that the predetermined SSGL artificial lift  10  injection initiation pressure set point programmed into the controller  90  is subject to errors that can be induced by fluctuations in production line  77  or ejection line  74  pressures (FIG. 4) due to the fact the operator must assume an average production line  77  or ejection line  74  pressure when programming the predetermined set point in controller  90 . Therefore, this method will perform best on wells with substantial rat hole  45  (FIGS. 2 and 3) or with very high liquid levels  31  where side string injection line  24  pressure will become noticeably elevated due to the production tube  41  liquid gradient. 
     The second embodiment of a method according to the invention, as schematically represented in FIG. 7, incorporates all the steps of the first embodiment illustrated in FIG. 6 plus the improvement step of injecting a relatively small or minuscule volume of injection gas from source  20  through a regulator  23  into the side string injection line  24  to remove the influx liquid level  33  in the side string tube  40  down to the level of the side string tube  40  connection on the injection mandrel  80  so that the pressure in the side string injection line  24  more accurately represents the head pressure in the production tube  41 . This method of controlling the SSGL injection cycle includes injecting a minuscule volume of gas into the side string at block  220  during the SSGL non-injection or off cycle. Simultaneously, the side string pressure is detected by pressure sensor  92  as a measure of the level of liquid  34  in the production tube  41  as represented at block  210 . When the minuscule volume of gas is injected, the pressure at surface in the side string injection line  24  will rise until all of the liquid is expelled from the side string injection tube  40 , at which time the pressure in the side string injection line at surface will stabilize. The volume of injected gas can be monitored or can be estimated during this step. The removal of all the influx liquid  33  (with its accompanying unknown level) in the side string tube  40  causes only a gas gradient to be present in the side string tube  40  and thus leads to a more precise liquid level computation in the production tube  41  and therefore the annulus  46 . The operator can then use this more precise liquid level detection method to enter a predetermined value representative of the desired liquid level in the well bore. This predetermined value is referenced by the controller  90  at block  212  and subsequently the SSGL injection cycle is automatically initiated for an arbitrary period of time by the controller  90  by opening valve  21  at block  214  when the monitored liquid level as determined by pressure is substantially equal to the predetermined set point in the controller  90  as represented at block  212 . As in the method of FIG. 6, a time delay represented at block  216  can be provided to allow the liquid column and/or plunger  82  to reach the surface and also allow the plunger  82  to return under gravity to its position proximal to the side string injection tube  40  inlet to the injection mandrel  80  before commencing another reiterative monitoring of the production tube  41  liquid level  34 . 
     While this method is more accurate than the method of FIG. 6, it is still prone to the same weakness as the first method in that fluctuations in production line  77  or ejection line  74  pressures are not compensated for and it may be necessary for the operator to assume an average production line  77  or ejection line  74  pressure when programming the predetermined set point into the controller  90  to initiate the SSGL  10  injection cycle. Therefore, this method will perform best on wells with substantial rat hole  45  (FIGS. 2 and 3) or with a high annulus  46  and production tube  41  liquid levels where side string injection line  24  pressure will become noticeably elevated due to production tube  41  liquid gradient during the injection of the minuscule quantity of gas into the side string injection line  24 . 
     The third embodiment of the invention is shown most clearly in FIGS. 1,  4 ,  5  and  8 . The pressure sensor  92  senses the side string injection line  24  pressure increase caused by the influx of liquid  34  into the production tube  41  and a pressure sensor  91  fluidly connected to the ejection line  74  senses the pressure of the production tube  41 . The pressure sensors  91  and  92  are connected to the controller  90  by wires or through a transmitter to input a signal from the sensors  91  and  92  representative of the pressure in the ejection line  74  and the side string injection line  24 . Alternatively, sensors  91  and  92  can be replaced by a single transducer (not shown) that directly measures the difference between the line pressures. While pressure sensor  91  is shown attached to the ejection line  74  it may be attached to the well head or associated plumbing in any position that is equalized is such a way that the sensor  91  can correctly detect the pressure in the production tube  41  at surface. The liquid  32  entering the production tube  41  will rise until the combined head pressure of the liquid  32  and gas  30  in the production tube  41  will be equal to the combined head pressure of the liquid  32  and gas  30  in the annulus  46  at the injection mandrel  80 . However, the influx of liquid  33  into the side string tube  40  will only be a portion of the level of the liquid  34  in the production tube  41  because the motor valve  21  is shut and the side string tube  40  is not equalized with the production line  77  or ejection line  74  at the surface. This influx of liquid  33  will cause the pressure of the side string injection line  24  to rise until the combined head pressures of the gas in the side string tube  40  and the liquid in the side string tube  40  are equal to the combined head pressure of the gas and liquid in the production tube  41  at the side string tube  40  attachment port on the mandrel  80 . At this point, the difference between the side string injection line  24  pressure at surface and the production tube  41  pressure at surface multiplied by the appropriate liquid gradient pressure factor will give an approximate liquid level  34  in the production tube  41 . The reason the liquid level is only approximate is due to the fact that liquid has entered the side string tube  40  to compress the gas in the upper portion of the side string tube  40  which results in two different gradients in the side string tube  40 , one for gas and one for influx liquid  33 , the level of which is unknown. These pressure measurements are used in this embodiment of the invention by the controller  90  to compute a value representative of the liquid level  34  in the production tube  41 . This computed value is then compared to the predetermined set point in the controller  90  to determine when the level of liquid  34  in the production tube  41  reaches the desired level, at which time, the controller  90  will initiate the SSGL artificial lift  10  injection cycle. Thus, the pressure monitoring method of control of the SSGL cycle of this embodiment includes the steps of: one, reiteratively detecting both the side string injection line pressure and the production tube pressure at surface throughout the SSGL non-injection or off cycle as represented in blocks  210  and  234  and generating signals representative thereof; two, calculating a differential pressure between the side string pressure and production tube pressure as represented in block  251  based on the pressure signals, which is approximately representative of the level of liquid in the production tube; three, comparing the calculated differential pressure to a predetermined differential pressure representative of the desired level of liquid in the production tube as represented in block  230  and; four, initiating the SSGL gas injection cycle represented in block  214  when the measured pressure is substantially equal to the predetermined value. As in the first and second embodiments of the invention, a time delay represented in block  216  can be provided. 
     The improvement of this embodiment over the first two embodiments is that the system now compensates for fluctuations in production line  77  or ejection line  74  (FIG. 4) pressure. In this method, while the exact level of liquid  34  in the production tube  41  is not known, the pressure differential between the pressure in side string injection line  24  (as detected by pressure sensor  92 ) and the pressure in the ejection line  74  (as detected by pressure sensor  91 ) will represent a liquid head pressure constant, regardless of the fluctuations in production line  77  or ejection line  74  pressure. The difference between the side string injection line  24  pressure detected by pressure sensor  92  and the ejection line  74  pressure detected by pressure sensor  91  is then used by the controller to reiteratively monitor the level  34  of liquid  32  in the production tube  41  as represented by the pressure differential to determine when the liquid level  34  reaches the predetermined and desired level. The controller  90  then initiates the SSGL  10  injection cycle when the detected liquid level reaches the predetermined and desired liquid level (as detected by pressure) regardless of whether the exact production tube  41  liquid level  34  and annular liquid level  31  are known. 
     Referring now to FIG. 9, the fourth embodiment of the invention for control of the SSGL cycle includes the steps of: one, injecting a minuscule volume of gas into the side string as represented in block  220  throughout the SSGL non-injection or off cycle; two, simultaneously detecting the side string pressure by pressure sensor  92  at block  210  and production tube pressure by pressure sensor  91  as represented in block  234  and generating pressure signals representative thereof; three, calculating a differential pressure between the production tube pressure and side string pressure based on the pressure signals as represented in block  251 , the differential pressure being representative of the level of liquid in the production tube; four, comparing the measured differential pressure to a predetermined differential pressure representative of the desired level of liquid in the production tube as represented in block  230  and; five, initiating the SSGL gas injection cycle as represented in block  214  when the calculated differential pressure is substantially equal to the predetermined differential pressure value. As in the first three embodiments, a time delay as represented in block  216  is desirably provided. 
     This embodiment, like the previous embodiment, uses the pressure sensor  92  fluidly connected to the side string injection line  24  to sense the pressure increase caused by the influx of liquid  32  into the production tube  41  and the pressure sensor  91  fluidly connected to the ejection line  74  to sense the pressure of the production tube  41 . The improvement over the previous embodiment is the injection of a minuscule volume of injection gas from source  20  through the regulator  23  into the side string injection line  24  to reduce the liquid level  33  in the side string tube  40  down to the level of the side string tube  40  connection on the injection mandrel  80  thereby producing a single gradient pressure in the side string tube  40 , i.e., gas only. Thus, the differential pressure calculated will be an accurate representation of the liquid head pressure in the production tube  41 . The removal of all the influx liquid column  33  in the side string tube  40  results in only a gas gradient in the side string tube  40 . At this point, the difference between the side string injection line pressure  24  at surface and the production tube  41  pressure at surface multiplied by the appropriate liquid gradient pressure factor will give a very precise production tube liquid level  34 . The difference between the side string injection line  24  pressure detected by pressure sensor  92  and the ejection line  74  pressure detected by pressure sensor  91  can then be used by the controller  90  to compute the liquid level in the production tube  41  and initiate the SSGL  10  injection cycle when the computed liquid level substantially equals the predetermined and desired liquid level as represented by the predetermined set point in the controller. 
     Referring now to FIGS. 1,  4 ,  5  and  10 , yet another method according to the invention can be used with any of the four embodiments disclosed above. This fifth embodiment of the invention dynamically sets and resets the predetermined artificial lift initiation set point using values from the side string pressure sensor  92 , production tube pressure sensor  91 , differential pressure sensor  93  and production line pressure sensor  94 . The differential pressure sensor  93  is fluidly connected to a measurement orifice or other industry standard gas measurement device in the production line  77  and the pressure sensor  94  is fluidly connected to the production line  77 . The pressure sensor  93  and the pressure sensor  94  are electrically connected to the controller to input to the controller signals representative of the pressures sensed by the pressure sensors  93  and  94 . The pressure values from sensors  93  and  94  are used to determine the production gas  30  flow rate from the annulus  46  into the production line  77 . According to this embodiment of the invention, the predetermined pressure set point (PSI) for the first two embodiments, or differential pressure set point (DP) as used in the third and fourth embodiments to initiate the SSGL injection cycle, is automatically adjusted upwardly as represented in block  260  by the controller  90  to raise the liquid level  31  in the annulus  46 . This adjustment, in effect, increases the liquid level DP or PSI value necessary to initiate the injection cycle of the SSGL artificial lift system  10  and thus results in an increased liquid level  31  in the annulus so that the liquid level in the production tube  41  rises farther before initiating the SSGL injection cycle. As the liquid level rises, there will come a time when the gas production will decline within a specified time weighted average, as represented in block  262 . The time weighted average is determined through well known statistical analysis for the amount of production over a specified time period or number of SSGL cycles. At that point, controller  90  automatically begins the reduction of the predetermined PSI or DP value set point at block  264  to reduce the liquid level  31  in the annulus  46  by reducing the liquid level PSI or DP value necessary to initiate the SSGL injection cycle. The well bore response in the form of increased volumetric production is then monitored by the controller  90  as represented in block  266 . As the production increases within the specified time and volume parameters, the predetermined set point for the desired liquid level will continue to decrease until no more increase in production volume  266  is determined by controller  90  within the specified time or cycle parameters. At this stable production period, the PSI or DP values in the controller  90  enter a dormant or nonadjustment state at block  268  for an arbitrary period before the controller  90  will initiate another change to the predetermined set point. 
     In this dynamic and interactive method, maximum production down the production line  77  is balanced with optimum liquid level  31  in the annulus  46  to best automatically economize the volume of injection gas from source  20  necessary to sustain production. At the end of the specified non-management period, the liquid level management procedure described above will be repeated until the next dormant period. It is to be understood that the automated liquid level management method will be done with adjustments taking place over the course of many hours and possibly days, the end result being the maximum liquid level sustainable within a given well bore with minimal interference with production and a reduced need of injection gas. 
     A sixth embodiment of the invention will now be described with reference to FIGS. 1 and 11. A magnetic sensor (MSO)  95  is attached to the production tube  41  or lubricator  62  to detect the arrival of the plunger  82  at surface subsequent to the injection of a blast of injection gas from source  20  down the side string tube  40  during the injection cycle of the SSGL artificial lift system  10  to control the ejection of the liquid  32  in the production tube  41  into the ejection line  74 . The magnetic sensor  95  is electrically connected to the controller  90  to input to the controller a signal representative of the magnetic flux sensed by the magnetic sensor  95 . The plunger  82  travel time from the initiation of the SSGL injection cycle to surface is calculated by the controller  90  and used by the controller  90  to adjust the SSGL artificial lift system  10  injection gas volumes from source  20  to accommodate a varying liquid level  34  in the production tube  41 , thereby controlling the average velocity of the plunger  82  in the production tube  41  and the impact of the plunger into the lubricator  62  as the liquid  32  in the production tube  41  is being ejected into the ejection line  74 . The magnetic sensor detects the arrival of the plunger as represented in block  350  and transmits a signal representative of the plunger arrival to the controller  90 . The controller  90  in turn calculates the trip time for the plunger  82  and compares the detected plunger trip time over a time weighted average (which is determined through well known statistical methods for a number of detected plunger trip times over a predetermined number of cycles) with a predetermined plunger trip time set point and adjusts the volume of gas injected during the subsequent SSGL injection cycles so that the detected trip time matches the predetermined trip time set point. For example, if the calculated average trip time of the plunger at block  352  does not equal the predetermined set point as represented in block  354  and is longer than the predetermined set point as represented in block  356 , the gas volume in the subsequent SSGL injection cycles is increased as represented in block  360 . If the detected plunger trip time is less than the predetermined trip time set point represented at block  356 , the gas volume during the subsequent SSGL injection cycles is decreased as represented in block  358 . The predetermined plunger trip time set point is determined by dividing the distance between the bottom of the production tube and the surface of the ground by the desired average rate of travel for the plunger  82  from the bottom of the production tube  41  to the surface. This value is then used by the controller  90  to adjust the SSGL artificial lift system  10  injection cycle so as to either increase or decrease the plunger  82  trip time to allow the plunger  82  reach the sensor  95  at the desired time. The sensor  95  can be any suitable magnetic sensor which measures a change in magnetic flux. An example of a suitable sensor is an Omni sensor manufactured by OKC Products Company. This method and apparatus of this embodiment can be used with any of the five embodiments discussed above. 
     Referring now to FIGS. 12 and 13, an alternate arrangement for use with the sixth embodiment is shown. Although the system as illustrated in FIGS. 1-3 show a plunger  82  for removing liquid from the production tube, it is not always necessary nor desirable to use a plunger. Plungers are most commonly used in production tubes with little or no rat hole and relatively short liquid columns to be ejected from the production tube. The use of a plunger in this instance significantly reduces the percentage of liquid loss. However, in production tubes having rat holes and large columns of liquid, gas can be injected directly into the production tube without a plunger from the side string without a significant percentage of liquid loss. Common production tubes may contain as much or even more than 150 feet of liquid. In the event that a plunger is not used, it is still desirable to adjust the volume of gas injected into the side string to control the average liquid ejection velocity in the most efficient manner. For this purpose, a donut-shaped lubricator plunger  280 , preferably constructed of ferromagnetic material, is supported on a flange  282  within lubricator  62  or production tube  41 . A magnetic sensor (MSO)  95  is attached to the lubricator  62  or production tube  41  to detect movement of the lubricator plunger  280 . When gas is injected from source  20  down the side string tube  40  during the injection cycle of the SSGL artificial lift system  10  to eject the column of liquid  32  from the production tube  41  into the ejection line  74 , an upper portion of the liquid column will contact the lubricator plunger  280  when it arrives at surface. The force of the liquid displacing upward will move the lubricator plunger  280  in the direction of arrow  284  until lubricator plunger  280  contacts compression spring  286  and trips MSO  95 . Thereafter, the lubricator plunger  280  will fall under gravity and rest on flange  282  until the next SSGL injection cycle. The signal from MSO  95  is transmitted to the controller  90  and can be manipulated in the same way as the method of the sixth embodiment for adjusting the SSGL injection cycle. 
     In embodiments one through six, the injection of gas from the source  20  through the injection valve  21  and down the side string tube  40  is commonly described as a blast of gas which infers that the injection valve  21  is fully open from the source  20  to the side string tube  40 . However, under certain conditions such as a well having a deep rat hole, as shown in FIGS. 2 and 3, or in a well that may have a high bottom hole or head pressure in the formation  51 , it may be desirable to inject a sustained and controlled flow of gas from the source  20  through the injection valve  21  and side string tube  40  and into the production tube  41  to the surface. To this end, the controller  90  may be operably adapted to position the injection valve  21  in a partially open position to constantly inject gas from the source  20  through the side string tube  40  to constantly lift liquid  32  to the surface. The injection valve  21  may be adjusted to a more open or restricted position to maintain the side string tube  40  pressure or differential pressure within the desired parameters according to any of the pressure monitoring methods previously described. This sustained and controlled flow of gas is to be differentiated from the relatively small or minuscule volume of gas injected into the side string tube  40  for clearing any liquid from the side string tube. The minuscule volume of gas is insufficient to raise the liquid in the production tube to the surface. 
     In part  2 , as shown in FIGS. 15 and 16, bore holes using a beam pump  300  and a progressive cavity pump  307  are employed for raising the liquid  32  in the production tube  41  to the surface of the ground. FIG. 20 shows a submersible pump system for raising the liquid  32  in the production tube  41  to the surface of the ground. While each of these pump artificial lift systems  10  incorporate the side string tube  40  method of liquid level  31  detection, they vary from the SSGL method of artificial lift in that the side string tube  40  termination point  48  is in the annulus  46  because in these lift systems the production tube  41  will be completely full of liquid  32  to surface when the artificial lift system  10  is in operation. Therefore, the side string tube  40  termination point  48  is in the annulus  46  to detect the level of liquid  31  in the bore hole to provide for control of the artificial lift system  10 . Also, while the termination point  48  of the side string tube  40  is demonstrated as being substantially equal with the position of the pumps  310 ,  315  and  320  (FIGS. 15,  16  and  20 ) in the well bore it is to be understood that the termination point  48  of the side string tube  40  may be lower or higher than the pump as long as the side string tube  40  termination point  48  is below the lowest point in the well bore that the operator desires to control liquid level  31 . Further, in FIGS. 15,  16 ,  19 ,  20  and  23  pressure sensor and transmitter  91  is illustrated as being fluidly attached to the annulus to detect the differential pressure between the side string tube  40  and the annulus  46  to detect the liquid level in the bore hole  43 . Alternatively, pressure sensor  94  could serve the dual purpose of production line pressure  77  and annulus  46  pressure detection because the annulus  46  and the production line  77  are substantially equalized or alternatively, sensors  91  and  92  can be replaced by a single transducer (not shown) that directly measures the difference between the line pressures. Thus, the invention can be used to control the operation of a beam pump  300 , a progressive cavity pump  307  and a submersible pump  320 . 
     Referring to FIGS. 15 and 16, sucker rod  304  is connected to the pumps  315  or  310  at a lower portion of the production tube  41  and to a beam pump head  300  or progressive cavity (PC) pump head  307  at an upper portion to drive the pump in a conventional manner. The barrel pump  315  or PC pump stator  310  is positioned at the lower portion of the well bore and is adapted to pump liquid  32  from the bottom of the bore hole to the surface of the ground. A side string tube  40  extends down along the outside of the production tube  41  in the annulus  46  and is open at a bottom portion thereof to be fluidly connected with and terminated in the annulus  46 . Electric or hydraulic lines  418  are connected to the prime mover  412  to drive the beam pump  300  or PC pump head  307  to operate the pumps  315  or  310  respectively. The prime mover  412  is connected to a controller  414  which is connected to the controller  90  and controller  90  is use to control controller  414  to maintain the level of liquid  31  in the bore hole above a predetermined minimum and preferable also below a predetermined maximum as measured by any of the pressure measurement techniques disclosed herein. FIGS. 17,  18  and  19  are alternate well bore and well head configurations that can be used with the beam pump  300  or PC pump  307  artificial lift systems. 
     Referring to the submersible pump artificial lift system  10  in FIG. 20 the submersible pump  320  is located at the lower portion of the production tube  41 . In this arrangement the submersible pump  320  is attached to the production tube  41  and an electrical cord  322  passes through the well head  60  and is operably attached to the submersible pump  320  to lift the liquid  32  from the bottom of the bore hole to the surface of the ground and a side string tube  40  has a termination point  48  in the annulus  46  to allow for the detection of liquid level  31  in the annulus  46 . A prime mover control  414  is connected to the electrical cord  322  and to the controller  90  to allow controller  90  to control the submersible pump  320  to maintain the liquid level  31  in the bore hole above a predetermined minimum and preferable also below a predetermined maximum as measured by any of the pressure measurement techniques disclosed herein. FIGS. 21,  22  and  23  are alternate bore hole and wellhead assemblies that can be used with the submersible pump artificial lift system  10 . 
     In the embodiments of the invention as applied to the beam pump  300 , progressive cavity pump  307  and the submersible pump  320  artificial lift systems  10 , the pressure sensor and transmitter  91  is operably connected to the well casing  42  to detect the pressure in the annulus  46  and the side string tube  40  termination point  48  is in the annulus to allow for detection of the liquid level  31  in the well bore. The embodiments that will now be described can be used with, but are not limited to, the pump systems herein disclosed. Like numerals in the previous embodiments have been used to described like parts. 
     A method according to a seventh embodiment of the invention includes the operation and control of a pump associated with artificial lift systems. This method is similar to the first embodiment with the exception that a pump is controlled for removing liquid from the well bore instead of the gas injection. The basic method of controlling the pumping cycle as shown in FIG. 24, includes reiteratively monitoring the annulus  46  liquid level  31  by detecting the side string (sst) pressure with pressure sensor  92  as represented in block  210 . The controller  90  then compares the detected side string pressure to the predetermined set point as represented at block  215 . If the side string pressure substantially equals the predetermined set point, the side string pressure is again detected. When the well bore liquid level (as indicated by pressure) no longer equals the predetermined set point in the controller  90 , controller  90  will alter pump operations at block  240 . Altering of pump operations at block  240  can include but is not limited to increasing or decreasing pump speed and starting the pump or stopping the pump by use of controller  90  to control the prime mover control  414  as shown in FIGS. 15,  16  and  20 . After the altering the pump operations at block  240  a time delay as represented at block  218  is activated. This time delay allows for a period of stable pump operation to determine the effect of the altered pump operation on the liquid level  31  in the well bore. 
     As with the first embodiment, this method will require the greatest amount of operator intervention to work with nominal efficiency. This method will only give a rough estimate of the liquid level  31  in the annulus  46  due to the fact that there will be an influx of liquid  32  into the side string tube  40  the level of which is unknown. This method is also prone to error in that the predetermined “alter pump operation” pressure set point programmed into the controller  90  is subject to errors that can be induced by fluctuations in production line  77  pressures (FIGS. 15,  16 ,  19 ,  20  and  23 ) due to the fact the operator must assume an average production line  77  pressure when programming the predetermined set point into controller  90 . Therefore, this method will perform best on wells with substantial rat hole  45  (FIGS. 17,  18 ,  21  and  22 ) or with very high liquid levels  31  where side string tube  40  pressure will become noticeably elevated due to the annulus  46  liquid gradient. Further, this method is susceptible to errors that may be induced by any leak in the side string injection line  24  at surface causing a reduced side string tube  40  pressure and therefore an inability to detect the annulus  46  liquid level  31 . 
     An eighth embodiment according to the invention is similar to the second embodiment with the exception that a pump is used for fluid removal from the well bore, as represented in FIG.  25 . This embodiment incorporates all the steps of the seventh embodiment illustrated in FIG. 24 with the added improvement step of injecting a minuscule volume of injection gas from source  20  through a regulator  23  into the side string injection line  24  to remove the influx liquid level  33  in the side string tube  40  down to the level of termination point  48  of the side string tube  40  in the annulus  46  so that the pressure in the side string injection line  24  more accurately represents the liquid head pressure in the annulus  46 . This method for controlling the artificial lift system includes injecting a minuscule volume of gas into the side string at block  220  while simultaneously detecting the side string pressure by pressure sensor  92  as a measure of the level of liquid in the annulus represented at block  210 . When the gas is injected, the pressure at surface in the side string injection line  24  will rise until all of the liquid is expelled from the side string injection tube  40 , at which time the pressure in the side string injection line at surface  24  will stabilize. The volume of injected gas can be monitored or can be estimated during this step. The removal of all the influx liquid  33  (with its accompanying unknown level) in the side string tube  40  causes only a gas gradient to be present in the side string tube  40  and thus leads to a more precise liquid level computation in the annulus  46 . The operator can then use this more precise liquid level to enter a predetermined liquid level value into the controller  90  to be referenced by the controller  90  at block  215 . If the detected value is no longer equal to the predetermined value at  215  the pump operation is then altered at block  240  based on the pressure criteria. The altering of pump operation is automatically initiated by the controller  90  controlling the prime mover control  414  (FIGS. 15,  16  and  20 ) when the detected pressure is no longer equal to the predetermined set point in the controller  90  as represented at blocks  210  and  215 . As in the method of FIG. 24, a time delay represented at block  218  can be provided to allow for a period of stable pump operation to determine the effect the altered pump operation has on the liquid level  31  in the bore hole. 
     While this method is more accurate than the method of FIG. 24, it is still prone to the same weakness as the first and seventh methods in that fluctuations in production line  77  pressures are not compensated for and it may be necessary for the operator to assume an average production line  77  pressure when programming the controller  90  to alter pump operation  240 . Therefore, this method will perform best on wells with substantial rat hole  45  (FIGS. 17,  18 ,  21  and  22 ) or with a high liquid level  31  where side string injection line  24  pressure will become noticeably elevated due to annulus  46  liquid gradient during the injection of the minuscule quantity of gas into the side string injection line  24 . 
     The ninth embodiment of a method according to the invention is shown most clearly in FIGS. 15,  16 ,  19 ,  20 ,  23  and  26 , and is similar to the third method, with the exception of the operation of a pump for artificially lifting the liquid from the bore hole. The pressure sensor  92  senses the side string injection line  24  pressure increase caused by the influx of liquid  33  into the side string tube  40  and a pressure sensor  91  fluidly connected to the annulus  46  senses the pressure of the annulus  46 . The pressure sensors  91  and  92  are connected to the controller  90  by wires or through a transmitter to input a signal from the sensors  91  and  92  representative of the pressure in the annulus  46  and the side string injection line  24 . The liquid  32  in the annulus  46  will rise and enter the side string tube  40 . However, the influx of liquid  33  into the side string tube  40  will only be a portion of the level of the liquid in the annulus  46  because the side string  40  is not equalized with the production line  77  at the surface. This influx of liquid  33  will cause the pressure of the side string injection line  24  to rise until the combined head pressures of the gas in the side string tube  40  and the liquid in the side string tube  40  are equal to the combined head pressure of the gas and liquid in the annulus  46  at the termination point  48  of the side string tube  40 . At this point, the difference between the side string injection line  24  pressure at surface and the annulus  46  pressure at surface multiplied by the appropriate liquid gradient pressure factor will give an approximate liquid level  31  in the annulus  46 . The reason the liquid level is only approximate is due to the fact that liquid has entered the side string tube  40  to compress the gas in the upper portion of the side string tube  40  which results in two different gradients in the side string tube  40 , one for gas and one for influx liquid  33 , the level of which is unknown. These pressure measurements are used in this embodiment of the invention by the controller  90  to compute a value representative of the liquid level in the annulus  46 . This computed value is then compared to the predetermined set point in the controller  90  to determine when the level of liquid  31  in the annulus  46  reaches a point either greater or less than the desired level, at which time, the controller  90  will alter pump operation. Thus, referring to FIG. 26, the pressure monitoring method of control of artificial lift systems incorporating a pump includes the steps of: one, reiteratively detecting both the side string injection line  24  pressure and the annulus pressure  46  at surface as represented in blocks  210  and  236  and generating signals representative thereof; two, calculating a differential pressure between the side string pressure and annulus pressure as represented in block  250  based on the pressure signals, which is approximately representative of the level of liquid in the annulus  46 ; three, comparing the calculated differential pressure to a predetermined differential pressure representative of the desired level of liquid in the annulus  46  as represented in block  235  and; four, altering pump operation in block  240  when the measured pressure is no longer substantially equal to the predetermined value. As in the previous embodiment of the invention, a time delay represented in block  218  can be provided to allow for a period of stable pump operation to determine the effect the altered pump operation has on the liquid level  31  in the well bore. 
     The improvement of this embodiment over the seventh and eighth embodiments is that the system now compensates for fluctuations in production line  77  pressure. In this method, while the exact level of liquid  31  in the annulus  46  is not known, the pressure differential between the pressure in side string injection line  24  (as detected by pressure sensor  92 ) and the pressure in annulus  46  at surface (as detected by pressure sensor  91 ) will represent a liquid head pressure constant, regardless of the fluctuations in production line  77  pressure. The difference between the side string injection line  24  pressure detected by pressure sensor  92  and the ejection line  74  pressure detected by pressure sensor  91  is then used by the controller to reiteratively monitor the level  31  of liquid  32  in the annulus  46  as represented by the pressure differential to determine when the liquid level  31  reaches the predetermined value. The controller  90  then alters the pump operation when the detected liquid level pressure differential value no longer equals the predetermined set point regardless of whether the exact annulus  46  liquid level  31  is known. Again, alteration of pump operation can include but is not limited to increasing or decreasing pump speed and starting or stopping the pump system. 
     Referring now to FIGS. 15,  16 ,  20  and  27 , the tenth embodiment of the invention for control of artificial lift systems incorporating a pump is similar to the fourth embodiment, and includes the steps of: one, injecting a minuscule volume of gas into the side string line  24  as represented in block  220 ; two, simultaneously detecting the side string pressure  24  by pressure sensor  92  at block  210  and annulus  46  pressure by pressure sensor  91  as represented in block  236  and generating pressure signals representative thereof; three, calculating a differential pressure between the annulus  46  pressure and side string line  24  pressure based on the pressure signals as represented in block  250 , the differential pressure being representative of the level of liquid in the annulus  46 ; four, comparing the measured differential pressure to a predetermined differential pressure representative of the desired level of liquid in the annulus  46  as represented in block  235  and; five, altering pump operation represented in block  240  when the calculated differential pressure is no longer substantially equal to the predetermined differential pressure value. As in the previous three embodiments, a time delay as represented in block  218  is desirably provided. 
     This embodiment, like the previous embodiment, uses the pressure sensor  92  fluidly connected to the side string injection line  24  to sense the pressure increase caused by the influx of liquid  32  into the side string tube  40  and the pressure sensor  91  fluidly connected to sense the annulus  46  pressure. The improvement over the previous embodiment is the injection of a minuscule volume of injection gas from source  20  through the regulator  23  into the side string injection line  24  to reduce or eliminate the liquid level  33  in the side string tube  40  down to the level of the side string tube termination point  48  thereby producing a single gradient pressure in the side string tube  40 , i.e., gas only. Thus, the differential pressure calculated will be a very precise representation of the liquid head pressure in the annulus  46 . The removal of all the influx liquid column  33  in the side string tube  40  results in only a gas gradient in the side string tube  40 . At this point, the difference between the side string injection line pressure  24  at surface and the annulus pressure  46  at surface multiplied by the appropriate liquid gradient pressure factor will give a very precise annulus  46  liquid level  31 . The difference between the side string injection line  24  pressure detected by pressure sensor  92  and annulus pressure sensor  91  can then be used by the controller  90  to compute the liquid level in the annulus  46  and alter pump operation when the computed liquid level no longer substantially equals the predetermined level as represented by the predetermined set point in the controller. 
     Referring now to FIGS. 10,  15 ,  16  and  20  yet another method according to the invention can be used with any of the embodiments seven through ten disclosed above. This eleventh embodiment of the invention is similar to the fifth embodiment and dynamically sets and resets the predetermined set point for altering pump operation using values from the side string pressure sensor  92 , annulus pressure sensor  91 , the differential pressure sensor  93  and production line pressure sensor  94 . The differential pressure sensor  93  is fluidly connected to a measurement orifice, or other industry standard gas measurement device capable of outputting a signal representative of gas volume, in the production line  77  and the pressure sensor  94  is fluidly connected to the production line  77 . The pressure sensor  93  and the pressure sensor  94  are electrically connected to the controller to input to the controller signals representative of the pressures sensed by the pressure sensors  93  and  94 . The pressure values from sensors  93  and  94  are used to determine the production gas  30  flow rate from the annulus  46  into the production line  77 . According to this embodiment of the invention, the predetermined pressure set point (PSI) for the embodiments seven and eight, or differential pressure set point (DP) as used in embodiments nine and ten to alter pump operation, is automatically adjusted upwardly as represented in block  260  by the controller  90  to raise the liquid level  31  in the annulus  46 . This adjustment, in effect, increases the liquid level DP or PSI value necessary to alter pump control and thus results in an increased liquid level  31  in the annulus so that the liquid level in the annulus will be maintained at a greater level than before altering pump operations. As the liquid level rises, there will come a time when the gas production will decline within a specified time weighted average, as represented in block  262 . The time weighted average is determined through well known statistical analysis for the amount of production over a specified time period. At that point, controller  90  automatically begins the reduction of the predetermined PSI or DP value set point at block  264  to reduce the liquid level  31  in the annulus  46  by reducing the liquid level PSI or DP value necessary to alter pump operation. The well bore response in the form of increased volumetric production is then monitored by the controller  90  as represented in block  266 . As the production increases within the specified time and volume parameters, the predetermined set point for the desired liquid level will continue to be reduced until no more increase in production volume  266  is determined by controller  90  within the specified time period. At this stable production period, the PSI or DP values in the controller  90  enter a dormant or nonadjustment state at block  268  for an arbitrary period before it will initiate another change to the predetermined set point. 
     In this dynamic and interactive method, maximum production down the production line  77  is balanced with optimum liquid level  31  in the annulus  46  to best automatically economize the energy required by the pump to lift the liquid to the surface of the ground and sustain production. At the end of the specified non-management period, the liquid level management procedure described above will be repeated until the next dormant period. It is to be understood that the automated liquid level management method will be done with adjustments taking place over the course of many hours and possibly days, the end result being the maximum liquid level sustainable within a given well bore with minimal interference with production and a reduced need of energy for the prime mover  412 . 
     A twelfth embodiment of a method according to the invention in an artificial lift system (FIGS. 15,  16  and  20 ), to reduce or control the power requirements of a pump system during peak load hours, as shown in FIG.  28 . The method entails the responsible use of electrical energy by reducing the power requirement of the artificial lift system  10  during certain periods of the day with minimal well production interference by altering the artificial lift system  10  operation to reduce or increase the liquid level  31  in the annulus  46 . To this end, the liquid level  31  in the annulus  46  is detected from the side string pressure or from the differential pressure as described in embodiments seven through ten and as represented in block  390 . Real time is monitored by the control  90  at block  391  and compared to the relevant specified time period in blocks  392  or  400 . Subsequently, the predetermined pressure set point for altering pump operation is adjusted in blocks  393  or  401  or the pump is shut down in block  405 . The predetermined PSI or DP set point in block  393  or  401  is compared in block  394  to the detected side string or differential pressure in block  390 . Subsequently if the detected pressure in block  390  is determined in block  394  to be greater than the appropriate predetermined PSI or DP set point in block  393  or  401  the state of pump operation will be monitored in block  397  to determine if the pump needs to be started in block  398  or if the pump speed should be increased in block  399  if a variable speed drive is available on the particular artificial lift system. Further, if at block  394  it is determined that the side string pressure or differential pressure value detected at block  390  is not greater than the predetermined value set in block  393  or  401  the pressure as detected in block  390  will then be compared in block  395  to the predetermined value set forth in block  393  or  401  to determine if the detected pressure represents a liquid level value that is less than the optimum level of liquid in the well bore. Next, the detected pressure in block  390  is compared in block  402  to a predetermined minimum PSI or DP as provided at block  402 . This predetermined minimum can be the reduction value set in block  401  or the normal operational value set in block  393 , or any other value that prevents pump damage. If the measured pressure is not less than the predetermined value, the pump speed can be reduced at block  403  in wells using an artificial lift system incorporating a variable speed drive. Alternatively, the pump can be shut down at block  405  if the side string pressure or differential pressure has declined below the predetermined minimum value set forth in block  402  to keep the artificial lift system from pumping off and damaging itself. A delay time is provided in block  396  to allow for a period of stable pump operation to determine the effect the altered pump operation has on the liquid level  31  in the bore hole. 
     Thus, a very desirable method of energy efficiency based on liquid level detection in a bore hole to control the artificial lift system by the above method is demonstrated. As is commonly known, peak load hours require utility companies to invest large sums to meet the high demand caused by residential use for a short period in the morning and evening. Often oil and gas wells are drilled in great numbers in small geographical areas and use electrical power from the same power grid as supplies the surrounding residences. If the power requirements for the oil or gas well artificial lift systems can be reduced or eliminated during the peak residential load hours a benefit will be realized by all the parties involved in electricity production and usage. In this method time is monitored relative to the peak load time established by the electrical utility company and pump operations are altered to balance the liquid removal requirements of the well bore and reduce energy consumption at an appropriate time. The pump artificial lift system can be shut down to prevent the system from drawing power during peak hours but this shut down may cause the liquid level to rise in the well bore and reduce production down the gas production line. In this new and unique method the controller detects a time prior to peak load hours and adjusts the predetermined set point of liquid level in the well bore to a minimum value. Subsequently the pump operation is altered to reduce the liquid level in the well bore to substantially equal the predetermined value then during the peak load hours the pump system can be shut down or operated at a reduced speed to either eliminate or reduce the artificial lift system power draw from the electrical grid. Further, because the liquid level has been reduced to a minimum level the empty rat hole in the well becomes storage for liquid entering the well bore to minimized the effect of liquid level on production volumes due to the fact the liquid must first fill the rat hole before it can begin to cover the productive formation and interfere with production. In this method, while the pump will require increased amounts of energy to reduce the liquid level into the rat hole below the productive formation, the energy will be required at an off peak load time when the electrical grid has power to spare. In this embodiment the prudent and timely use of electrical energy will benefit all parties involved with the electrical grid while allowing the operator minimize impact on production. 
     Referring now to FIG. 14, a plurality of artificial lift systems  10  having a respective local controller  90  can be arranged at a number of well sites. Each controller  90  includes a telemetry unit  290  that receives signals from pressure sensors  91 ,  92 ,  93 ,  94  and MSO  95 , and any other system parameters and then transmits them to data receiver and control transmitter unit  292  in a well known manner. These signals are then transferred to a central controller  294  that can include a computer. The controller computer  294  separates, processes and performs the logic functions on the data for each well. The updated information is then transmitted back to the respective controller  90  through control transmitter unit  292  and the respective telemetry unit  290  to operate each well following any of the embodiments previously described, depending on each well&#39;s particular needs and the operator&#39;s preferences. In place of the telemetry unit  290 , conventional electrical lines can be used. Although a separate local controller  90  and remote central controller  294  have been described, it is to be understood that a single controller could be located at the remote location. Signals are directly transferred from the well and processed in the central controller  294 . 
     While particular embodiments of the invention have been shown, it will be understood, of course, that the invention is not limited thereto since modifications may be made by those skilled in the art, particularly in light of the foregoing teachings. For example, each method presented is capable of functioning as a stand alone improvement or being combined with any other of the methods presented to create either a partially dynamic or fully dynamic and interactive artificial lift control methods that can be used with the SSGL or pump artificial lift systems. Reasonable variation and modification are possible within the scope of the foregoing disclosure of the invention without departing from the spirit of the invention.