SYSTEM OF OPTIMIZATION OF PUMPS IN REAL TIME DESCRIPTION OF THE INVENTION The present invention refers to the operation of the bottom pumps, and more particularly, to computerized systems to optimize said gas and oil operation. As is well known in the industry, bottom pumps are used to achieve supplementary or artificial lift in order to transfer fluids from the subsurface formations to the surface of a producing well, after the reservoir pressure has decreased to a point where the naturally available energy is insufficient for production. Consequently, a general practice is to use bottom pump assemblies and associated systems to control the pump, and transport fluids stored in oil and gas wells to the earth's surface. For example, in the United States Patent ofAmerica No. 5,193,985, Escue et al. Discloses a pump control system that features a surface monitoring station to support radio communication with the motor and bottom pump assemblies. Several sensors incorporated in each set of motor and pump, send the corresponding signals indicating variables such as temperature and fluid levels, in order to control the conditions of the well and the pump. What is revealed by Escue makes it clear that the pump control systems of previous inventions are characterized by monitoring a minimum of variables and these have been inadequate to effectively identify the various anomalies of the pumps that have adversely affected the production of the wells. For the effective management of bottom pumps during the recovery of gas and oil, it is imperative to know the dynamic level of the pumping fluid. As the experts in the field know well, the dynamic level of the pumping fluid shows the relationship between the pumping rate and the productivity of the well, which, in turn, indicates to the oil field professionals the true behavior of the well. Therefore, the knowledge of the dynamic level of the pumping fluid, gives an idea of the well productivity, completion and conditions of the deposit. Moreover, the comparison between the actual value of the dynamic level of pumping fluid from a well and the theoretical capacity of the pump, provides a decisive view of the conditions and behavior of the well pump system. Experts in this area will easily understand that the pump loses efficiency as its various components wear out. During conventional oil well recovery operations, adjustment of the pump flow rate, which is achieved manually by adjusting the pump's RPM, is a prerequisite for maintaining the maximum productivity of the well, and as understood by those skilled in the art. If there is no knowledge of well conditions in real time, the analysis of well and pump behavior is not only limited by the lack of timely information but also takes a lot of time and dedication. Unfortunately, in the absence of automated, real-time analysis, the only way to notice changes in the requirements for pump performance is a catastrophic reduction in well production. Previously, to obtain the dynamic level of the fluid, a well operator had to resort to periodic, expensive and uncomfortable fluid level sonic tests. However, due to the problematic and wasteful nature of these fluid sonic tests, well operators usually make an estimate of the rate of production of the required production rate - and the corresponding pump performance - in an attempt for reaching the maximum productivity of the well. But there is a serious risk of excessively low fluid levels, which substantially impair the productivity of an oil well, damaging the pumping equipment at the same time. To avoid this risk of potentially disastrous conditions and consequences, operators often take conservative actions, thereby reducing the likelihood of maximum production from the oil well. As the experts in the field will notice, in the gas wells of the pumps they are used to extract fluid from the hole, thus releasing the back pressure in the formation. This backpressure produced by the accumulated fluid downhole, of course, reduces, and may even end, the production of the well. Operators place these pumps generally below the boreholes of the well, and the fluid level is reduced, until the gas flows back from the well. Commonly, the gas emanating from a well in the well will continue to flow until the back pressure returns, due to the continuous inflow of fluid into the well. Thus, it should be evident to those skilled in the art that, by automating a bottom pumping system and providing a continuous analysis of the pit and the conditions of the pump, the gas and oil production of the pump can be increased. a well in a way hitherto unknown in the industry. Additional advantages include longer pumps and wells as well as cost reduction, thanks to optimized well production and a substantial reduction in service needs. Having such an automated computer system would also guarantee obtaining optimum longevity and performance for the pumps used in pumping applications of progressive cavities and the like. Clearly, the advantages derived, in terms of reducing labor costs and greater productive performance of the oil or gas well, are obvious. Among the oilfield automation and production engineers who handle progressive cavity pump systems and the like, it is generally known that there is a peculiar difficulty with respect to the efficient automation of such pump systems, under a real-time optimization protocol and closed loop. The instrumentation to collect the prerequisite data is not only prohibitive in terms of cost, but also, the information provided by this collected data must be processed and analyzed completely to ensure that global optimization can be carried out. This type of automated system for the pump of an oil well has not been previously disclosed in this field. In fact, the attempt to build this system using currently available instrumentation usually requires the performer to place pressure sensors on the suction and discharge of the pump. This approach to trying to automate the bottom pump systems is obviously costly and mechanically evasive, because the components of the pump that are being controlled are located in the subsoil. These limitations and disadvantages of the previous inventions are thus overcome with the present invention, in which a particularly useful computer system is offered to allow the monitoring and real-time analysis of the pumping operations during the recovery of wells from gas and oil, thus allowing production to be optimized. The pumping system explained in the present invention offers the automation and production engineers of the oil field, a complete and profitable analytical and automation tool. The present invention offers a system for optimizing the operation of the pump during the recovery of gas and oil. As will be described later in detail, by means of the strategic arrangement of several sensors along the production pipe and suction rod string, and the related bottom apparatus, the operation and behavior can be monitored in real time. of the bomb. It has been determined that the dynamic level of the fluid is an important indication of the behavior of the pump. In consecuense, the present invention proportional to the operator or end user the dynamic level of the fluid, on a real-time basis.
As a prerequisite to achieving optimization of the pump, the present invention analyzes the dynamic level of the fluid and other pertinent data, allowing to have a convenient means and method to make corrections to the pumping system in the field and during the operation. Those skilled in the art will understand that the present invention includes a computerized system with inherent and adaptable knowledge, sufficient to interpret the conditions of the pump based on various variables and parameters, in order to increase or decrease the production of this and maintain a dynamic level of fluid determined as the optimum, or otherwise advantageous, by the end user. The computer system explained in the present invention includes a user interface, of the intuitive type, for data entry, as well as a standard database on the operational behavior of the pump. This invention is designed with a range of configurations to cavity the remote administration of several wells, using serial communications and remote control transmission devices. In accordance with what is disclosed by the present invention, a methodology has been discovered that allows optimizing the production of the bottom pump. Accordingly, as will be described later in detail, one of the objects of the present invention is to provide a mechanical assembly and integrated computer system to achieve optimization of the bottom pump in real time. Also, an object of the present invention is to provide the means and the method to monitor and optimize the dynamic operating conditions of a bottom pumping system. A further object of the present invention is to provide the means and the method to monitor and optimize the dynamic level of the fluid of a bottom pumping system. Another object of the present invention is to provide the means and the method to sustain a knowledge base of raw data indicating the dynamic operating condition of a bottom pumping system. Still another object of the present invention is to provide the means and method for applying other bottom pumping systems, a raw data knowledge base indicative of the dynamic operating condition of a bottom pumping system. The present invention has the advantage and features that the bottom pumping operations are monitored and optimized in a way, and with means previously unknown in the industry. These and other objects and features of the present invention will be apparent from the following detailed description, where reference is made to the illustrative examples and related tables, as well as to the figures in the accompanying drawings. BRIEF DESCRIPTION OF THE DRAWINGS FIGURE 1 illustrates a simplified diagram of the preferred embodiment of the present invention. FIGURE 2 illustrates a simplified diagram of a portion of the preferred embodiment illustrated in FIGURE 1. FIGURE 3A illustrates a front cross section of the portion corresponding to the head of the preferred embodiment illustrated in FIGURES 1 and 2. FIGURE 3B illustrates another frontal cross section of the part corresponding to the head of the preferred embodiment illustrated in FIGURES 1 and 2. FIGURE 4 shows a schematic diagram of the computerized system logic and data flow corresponding to the preferred embodiment of the present invention. FIGURE 5 shows a schematic diagram of the General Loop for the PLC (Programmable Logic Controller) of the present invention. FIGURE 6 shows a schematic diagram of the diagnostic procedure of the present invention. FIGURE 7 shows a simplified load versus time plot, in which the runoff reduction treatment of the pump according to the present invention is illustrated. FIGURE 8 shows a plot of RPMs of the pump against measured axial load of the bearings, corresponding to a pumping system that behaves according to the present invention. FIGURE 9 illustrates a wellhead pressure plot against pump RPMs, corresponding to a pump system that behaves according to the present invention. FIGURE 10 illustrates a fluid level plot against pump RPMs, corresponding to a pump system that behaves according to the present invention. FIGURE 11 illustrates a level plot of. fluid versus pump flow rate, corresponding to a pump system that behaves according to the present invention. The pumping optimization system contemplated by the preferred embodiment of this invention comprises a mechanical assembly which includes a progressive cavity pump ("PCP"), monitoring elements to continuously and in real time determine the behavior of the pump of a pump. well, and an expert computer system to analyze the behavior of the pump and adjust accordingly the characteristics of it, in order to optimize the production of the well As is known to those skilled in the art, a PCP pump comprises a stator with a steel tube, which has an elastomer inside it, and a rotor that rotates inside the stator.The stator hangs on the extensions or strings of oilfield production pipes.The rotor hangs on the extensions or strings of rods of oil field suction The production pipe and suction rods mentioned are obviously tubular elements commonly used in the industry. ustria of exploration and recovery of gas and oil. A head provides support to the suction rods, giving rise to a pushing capacity and allowing to transmit the torque provided by the electrical power, from gas engine or diesel engine. As understood by those skilled in the art, the length of each of the corresponding production pipes and strings of suction rods varies according to the depth at which the pump is required to be fixed, in relation to the location of the oil field. or gas. Once installed, the production pipe and the stator maintain a vertical vertical rise in the well: the pipe and the stator must maintain a critical spacing with respect to the suction rod, in order to guarantee a permanent and correct alignment of the rotor of the stator As experts in this field will notice, the stator provides a stop below its elastomeric section, to indicate the location of the rotor during installation. Said installation is usually carried out with the hoisting units in the oil field, or "derrias" of well service. These specialized equipment consist of a mast and a mechanical winch almost similar to the winch used by a conventional crane. In the simplified diagrams of FIGURES 1 and 2, the complete system is illustrated to optimize in real time the behavior of the bottom pump as contemplated by the present invention. More particularly, FIGURE 1 shows the surface components that constitute the preferred embodiment. In a manner known to those skilled in the art, the head 125 is fixedly attached to the brake 120 and the coupling 115. The coupling 115 is coupled with the gearbox 110 which in turn is attached to the drive motor 105. As will be understood by those skilled in the art, the gearbox 110 controls the speed of the motor 105 communicated to the drive shaft 130. The flow line 5 bifurcates from the production line into a flow "T" 140 where a transducer 25 It monitors the discharge pressure on the surface. Likewise, the transducer 20 is placed in the annular space, to monitor the pressure of the casing. The gas can rise in bubbles through the casing 150, and obviously, in a manner known in the industry, said casing can be extended to a gas collection system or discharged into the atmosphere away from the well to avoid security risks and the like. The axial load on the head 125 is monitored by the load sensor 180. As clearly illustrated, the output produced by the pressure discharge transducer on the surface 25, coating line pressure transducer 20, and load sensor 180, is electrically communicated to a programmable logic controller ("PLC") 400, or to a computer personal ("PC") field containing an integrated PLC, a remote control unit ("RCU") and an advanced control unit ("ACU"), as will be described later in detail. The communication link 85 is interconnected with the PLC 400 and the variable drive 80 which controls the speed of the motor 105. The electric power line 75 is electrically communicated with the pulse motor 105 and the variable frequency drive 80. The present invention It also contemplates the communication between the PLC 400 and similar, with a remote PC 450, that contains an ACU allowing the connection by radio, modem, direct cable connection, etc. In the drawing the production pipe string 145 contained within the casing pipe 150, common in the background inventions, is shown.
The optimization system of the pump in real time according to the present invention, thus makes a follow-up to the variables, offering an idea of the relationship between the discharge pressure of the pump and the bottom thrust in the head, it has been found that the determination of the amount of load supported by the thrust bearings of the head constitutes a key to perform this analysis, particularly on a real-time basis. Preferably, a resistive load sensor, of the bridge type, measures this load of the thrust bearings of the head. The analog results of other pressure transducers indicate the discharge pressure at the surface and the pressure of the casing. Simultaneously, the motor current is monitored in the spindle motor. As those skilled in the art will notice, these analog values are analyzed to establish the dynamic operating conditions of the pumping system pump; to determine the dynamic level of the fluid in the well, and to provide raw data for the analysis of the operating situation of the pumping system. In the preferred embodiment of the present invention, a PLC or a PC with industrial resistance acts as the communication center linking the mechanical drive and the expert computing system. As understood by those skilled in the art, the PLC is configured to store data and operate the pump system, based on basic information obtained from the expert computer system. The PLC also provides the interface to manage the behavior of the pump from a remote location. It should be evident that, for a non-automated application of the present invention, the PLC can be excluded; in these circumstances, it is clear that the expert system of the present invention would preferably interconnect with instruments that provide information in the head, directly from a portable computer transferred to the field. In some applications, an industrial PC configured with analogue and digital input / output (I / O) can be used in the field site, as appropriate. It should be evident that the expert system explained in the present invention would be loaded into this PC, thereby operating the complete pump optimization system in the field, at the local site. Using technology known in the field, the system contained in the PC or PLC can be managed from a remote location, through modem or radio link. Referring now to FIGS 1 and 2, there is illustrated a simplified diagram of a preferred embodiment for the bottom rotor-stator assembly, comprising a mechanical aspect of the present invention. As is well known in the industry, the term "background" is contemplated to indicate that a nested device is placed underground within the annular space of a gas or oil well or reservoir. In a conventional manner also known to those skilled in the art, the casing extends down from the well head and is perforated at its lower end to allow the formation fluid to circulate there and then be forced to rise to the surface. In particular, the formation fluid is conducted to the surface by circulating to it within a string of production tubing contained in the casing. Gaskets are generally used to seal the annular space between this casing and the production pipe string. The rotor-stator assembly 100 of the oil field pump system, which is explained in the invention, comprises a rotor 160 and a stator 170. The rotor 160 is preferably constructed of an external helix of highly resistant and precision machined chromed steel. . The stator 170 consists of an internal helix preferably precision molded from a durable synthetic elastomer. A conventional installation for the recovery of gas and oil incorporates said stator in the string of production pipe 145. Several suction rods 155 adjusted to the requirements of the American Petroleum Institute ("API"), are configured to suspend the rotor 160 within the stator 170 and drive the rotor 160 rotatably. It will be understood that the suction rods 155 suspend the rotor 160 within the corresponding stator 170 and drive the rotor 160 in the direction of rotation. That is, as shown in FIGURE 2, the rotor 160 is driven by the suction rod string 155 which is connected at its lower end with the rotor 160 and extends into the production line 145 to the surface. The suction rod string 155 is rotatably driven by the head of the surface 125, which operates the pump 100. The string of pipe 145 contemplated in this invention secures the stator 170, as a stationary member of the pump assembly, to a fixed underground elevation. FIGURE 2 illustrates the pump assembly at a level of more than 6,000 feet below the surface. As will be appreciated by those skilled in the art, when the rotor 160 and the stator 170 are in place, sealed cavities are formed. Then, as the rotor 160 rotates in the corresponding stator 170, these sealed cavities are raised to discharge the pumped fluid in the pipe string 145. The progressive cavity pump 165, a basic component of the preferred embodiment, consists of a 160 single helical rotor meshing with a double helical stator 170, which is attached to the bottom of the pipe string 145. The rotor 160 is commonly attached to the string of suction rods 155 which is suspended and moved rotatingly by the head of the surface 125. The heads 125 mounted on the surface, support and rotate the string of suction rods 155 thus transferring the torsion to the pump of progressive cavities 165 that is found downhole. The rotary movement is usually obtained through the action of a pulley and belt drive system whose speed can be fixed or variable. The variable speed, it can be mechanical or electrical. As the rotor rotates eccentrically within the stator of a progressive cavity pump according to the present invention, a series of sealed cavities is formed which progress from the suction end to the discharge end of the pump, in a manner well known in the art. industry. This is how a continuous flow of positive displacement is created, which has a discharge rate proportional to the speed of rotation of the rotor and to the differential pressure in the pump of progressive cavities. The head 125, which includes bearings, seals, etc., is located on the surface of the well. required to rotate several API rods 155, in a manner known in the industry, thus rotating the rotor 160 within the stator 170. Since the progressive cavity pump 165 contemplated in the present invention is a positive displacement pump, custom-made that the speed of rotation of the pump 165 varies, the production of said pump undergoes a proportional change. As those who practice in this area will appreciate, the applications of the oilfield progressive cavity pumps vary significantly depending on the depth at which the pump assembly is installed and the pre-burst pumping rate to maintain the desired fluid production. . In this way, the preferred embodiment of the present invention comprises a set of mechanical devices and raw data collection. The head 125 comprises a support structure that supports the drive shaft 130 of the pump system, and axial and radial bearings to provide a conventional mechanism that rotates several suction rods 155 that rotate the rotor 160 in the stator 170. The assembly isolates the pumped fluid F, by means of the stuffing box or seal 135 in order to provide a manageable discharge of the fluid F. The head 125 contains axial and radial bearings that conventionally support the load L attributable to the plurality of rods 155, the fluid column F, and the pump 165. As is well known in the industry, the bearings are used to centralize the shaft of the head 130. The head 125 makes it possible to isolate the elements that bear the load on the bearings axial thrust, and of course, the head itself. This insulation helps to measure the axial load L by means of hydraulic or electronic instrumentation 400, which is placed between the thrust bearing of the head and the latter. According to conventional practice, the head 125 is configured by conventional devices such as coupling 115 and gearbox 110, to receive various joint motors 105, motors and other main common impellers. Referring now to the front cross section of the head 125 and the related components illustrated in FIGS. 3A and 3B, it will be understood that an important aspect of the present invention is the mechanical relationship created by the effect of the pump discharge pressure. and the downward thrust in the head, in relation to the bottom pump system. Certainly, as will be described later, in order to monitor this mechanical relationship, it has been found advantageous to establish a value for the suction pressure that exists in the bottom hole. This information is determined by measuring the amount of load carried by the thrust bearing of the head. As will also be understood by those skilled in the art, the present invention employs a suitable load sensor, such as, for example, a resistive bridge type or a hydraulic load sensor and an analog pressure transducer, to measure this load. Accordingly, the head 125 conventionally includes a bearing housing for accommodating both axial and radial bearings, and constitutes an upper cover for sealing the system against contaminants in the environment and for containing the radial bearings. It will be noted that the axial bearings support the fluid weight, the plurality of rods and the load of the pump, the radial bearings center the spindle axis and provide the system with a radial load capacity. As is well known in the industry, the upper seal and lower seal work in combination to keep grease in and dust out. Brake elements 120, prevent the backward rotation when the force has stopped rotatingly driving the suction rod. The stuffing box or shaft packing 135, provides a mechanical seal of the fluid between the atmosphere and the pipe 145 filled with the latter. This assembly then makes it possible to isolate the fluid from the pump F, by means of the stuffing box or seal 135, allowing a manageable discharge of the fluid. Also illustrated is the load sensor 180 which is a device for measuring the mechanical load. In the preferred embodiment of the present invention, as illustrated by the frontal cross sections shown in FIGURES 3A and 3B, the load sensor 200 comprises a hydraulic or electronic load sensor positioned below the cone 230 and the seat 225 of the thrust bearing. As the experts will notice, there are two prevailing load sensors that are generally used in inventions for the oil field: a hydraulic load sensor and a strain gauge sensor. The conventional hydraulic load sensor .200 illustrated therein is contained within the casing 245, shown relative to the shaft 130 and the shaft sleeve 240. The load sensor 200 comprises the piston 220 and a corresponding loading cylinder, seals of silicon in "O" 215, pressure transducer 205 and a conventional inlet valve. Also illustrated is the purge plug 260, the bearing spacer 250, pressure output elements of the pump and valve 210, as well as a load sensor receiver 255. As will be appreciated by those skilled in the art, the hydraulic load sensor 200 is positioned below the axial bearings and the head shaft., and it provides support. In a manner known in the industry, the piston 220 of the hydraulic load sensor _200 raises the axial bearings so that the load sensor piston carries the same load as the axial bearings. As should be apparent to those skilled in the art, this load corresponds to the weight of the total load of the hydraulic fluid, plus the weight of the plurality of rods submerged in the fluid. The pressure transducer registers this force (attributable to the load) on the piston of the load sensor. The axial load of the system is known due to the fundamental relationship between pressure and force: Load, LB = pa x Phs where, LB is the load of the system due to the sum of the weight of the fluid column, rods, pump, etc. ., pa, is the piston area of the charge sensor, and Phs, is the pressure recorded by the load sensor. Referring now specifically to FIGURE 3B, in another embodiment of the present invention the load sensor 270 is constituted by a strain gauge sensor comprising a push button extensometer 275, a load sensor frame 285 and contact pins 280. Consistent with the present invention, this system is located below and serves as support for the axial bearings and the spindle axis, the extensometer 275 being placed on the edge of the frame of the load sensor 285. Two contact pins 280 with the same altitude, they are placed on the same central line from the axis 130 at intervals of 120 °, thus arranged equidistantly with respect to the button extensometer 275. The extensiometer is placed at 0 or 360 °, with the first pin at 120 ° and the second at 240 °. As should be apparent to those skilled in the art, this arrangement helps distribute an equal burden among these three elements. The load sensor frame supports the same load as the axial bearing. This force (load) on the frame of the load sensor is transferred to the button load sensor and to the two contact pins. The button load sensor supports one third of the total axial load. The stress sensor registers this load. The experts in the matter will notice that one of the advantages of measuring a third of the total axial load, is the smaller size and cost in relation to the extensiometer, which imparts physical and economic feasibility to the design. FIGURES 1-3A also illustrate a transducer 205 of the head pressure of the wellhead, which provides an analog value to represent the discharge pressure at the surface. As will be understood by experts in the field, the discharge pressure at the surface is the pressure required to overcome the co-pressure or surface restriction that exists in the collector system flow line. This discharge pressure on the surface corresponds to a variable dependent on factors such as the viscosity of the well fluid, the number of operating wells (discharging into the same collector system), the size of the flow line, the flow rate , changes in elevations, etc. The pressure transducer 120 of the casing is illustrated in order to provide an analog value that represents the pressure in the annular space due to the gas associated with the production of oil or gas. The frequency variator 80 allows adjusting the speed of the pump by changing the frequency of the alternating current supply to the induction motor that rotates the driving shaft of the head, and provides the computer system explained in this invention, the feedback corresponding to the current the motor. Also illustrated is the drive motor 105, which provides rotary force to the drive shaft, rods and pump components. As will obviously be understood by those skilled in the art, the driving motor 105 may be configured as a direct drive motor, chain drive motor and gear, etc., as appropriate for the optimal performance of the pump that is contemplated in these memories. descriptive With reference now to the schematic diagram that appears in FIGURE 4, illustrates the logic and data flow that characterizes the expert computing system contemplated by the present invention. As will be understood by those skilled in the art, the computer system disclosed by this invention is comprised of a field instrumentation unit, a field instrumentation organizer ("FIU") 10, a programmable control unit ("PLC"), or remote control unit ("RCU") 400, and an advanced control unit ("ACU") 450. Also shown is a variable speed controller 60, historical data unit 415 of the PLC, software interface unit 430, unit of sizing program / productivity analysis 500, and real-time analysis unit, 470. More particularly, referring now to FIGURES 1-2 and 4, the FIU unit, 10, receives inputs from the load sensor 180, from the transducer of pressure of the flow line 25, of the pressure transducer of the casing pipe 20, of the transducer of the temperature of the engine 30, and additional variables 35, as described in this writing. As also described above, the surface head 125 provides the measurement corresponding to the axial face supported by the axial bearings. The FIU 10 unit consists of the well surface instruments needed to transmit all operational data from the well to the RCU unit, 400, and is based on industrial instrumentation standards. The RCU 400 unit executes the basic control rules to optimize the system of the progressive cavity pump according to the present invention, in order to protect the pump so that it does not operate under extreme conditions and to guarantee the continuous operation of the well . The RCU unit also performs the communication interface between the ACU unit, 450, or the SCADA system, based on standard protocols.
The ACU 450 is the expert system contemplated according to the present invention and executes the advanced control rules to optimize the production of the well, carrying out an advanced analysis and diagnosis based on real-time information coming from the field. The ACU unit generates well control actions and alarm messages in an operator console, followed by a detailed explanation of them. Representative control actions include adjustment of RPMs, adjustment of valve opening percentages, etc. As will be described hereinafter through its real-time analysis 470, the ACU 450 unit also provides the user interface with the sizing and behavior modules of the pump 500 proposed according to the present invention. As will be understood by those skilled in the art, the basic rules contemplated by the present invention, comprise rules that adjust the speed of the pump to control the rate of production, in order to obtain a desired fluid level and provide alarms and / or stops that prevent the damage to the expensive components of the pump. The speed of the motor and consequently the output of the pump 80, are determined through a variable controller device 60, that is, a servomotor control, using control data that comes from, or goes to, other system devices. , as described herein, including diluent control devices, local alarms and other on-site devices, which require automation. On the other hand, the advanced rules include rules generated through the representation of a knowledge-based oil field experience, with which production can be maximized, the possibility of operational failures reduced to a minimum, possible failures of the Pump and well condition can be determined, and appropriate preventive measures can be recommended to optimize pump operations. As will be understood by those skilled in the art, the ACU unit disclosed in the present invention may use information from the RCU, whether it is directly integrated with the RCU or interconnected with a SCADA system, with support for standard 430 interface protocols corresponding to versions. autonomous or network, such as DDE, TCP / IP, etc. Connection options include radio modem links for dedicated or non-dedicated telephone lines, or direct connection 90. Of course, it will be understood that the ACU and the RCU can be linked in a dedicated industrial PC located in the field. It will also be understood that the ACU unit can network, control and operate various pump installations contemplated under the present invention.
Therefore, it will be appreciated that the present invention offers a computer system (see FIGURE 5) to optimize the performance of the bottom pump, using real-time data supplied by commonly available economic transducers, and the like, which are placed strategically within the well head assembly, as described previously and in detail here. In general, those skilled in the art have sought to automate the operation of PCP in real time and with a closed loop, but they have not been able to avoid the use of expensive instruments and the like that have typically been located downstream. In addition to providing sufficiently accurate and up-to-date information, this kind of optimization system must efficiently process and analyze such information so that it is possible to make appropriate adjustments in the field, in real time, or at least close to real time. As will be described hereinafter, the aspects referring to the software of the preferred embodiment of this invention have been developed in C ++ for Windows of Microsoft 3.1, 95 or NT platforms, being compatible with TCP / IP, standard DDE communication protocols and with any application that complies with these protocols. It has been designed with Client / Server architecture and obviously, within what is proposed by this invention, it fits any other suitable language of application in any known platform. To perform the deductive tasks of the engine according to the present invention, Artificial Intelligence techniques are used, such as neural networks, Fuzzy Logic and genetic algorithms. By way of example, as will be described below, a fuzzy logic module manages the task of comparing and detecting the conditions of the variables. To prevent ambiguous conditions from occurring, a diffuse set consisting of four conditions for each variable is used. Another aspect of the present invention is the automation and software analysis comprising the expert system and related systems. In the preferred embodiment, the analytical tool of the design of the progressive cavity pump systems 22, comprises software that develops mathematical models of a well with progressive cavity pump, to decide the potential of the well. According to the present invention, the well potential corresponds to the ratio of the inflow performance ratio (IPR) to the output behavior ratio (OPR) This aspect of the present invention also determines the appropriate size for the equipment of the pump of progressive cavities to be used for a well, that is to say, the pump, heads, rods, etc.
This analytical tool operates on-line and off-line, and includes a database that allows saving and retrieval. Concentrating now on the potential of the well, we have that the nodal analysis module of the preferred incorporation, allows to generate curves of the behavior of input and output of the well and its completion. It is possible to establish and fix the operation point of the well for the analysis of the parameters of operation, design or redesign. Operating parameters include the desired fluid level or rate, hydraulic power, mechanical power and electrical power. The study of the completion of wells is possible through the use of multiphase correlations of flow, both horizontal and vertical, for light, medium, heavy or extra heavy crude. By using these analyzes, you can determine the optimal production rate desired for the well. It is also possible to decide the pressure differential (Delta P) necessary in terms of the pump; Delta P, defines the hydraulic power required by the pump. As will be described below, according to the present invention it is also possible to determine the suction pressure (fluid level) for the optimum performance of the well. Using a variety of mathematical correlations, one can predict the mechanical loads handled by the head and the motor (or other main driver).
In order to achieve the objectives of the pump optimization of the present invention, a prerequisite is to calculate the friction and density to establish in turn the proper calculations of fluid levels, due to the impact that friction and density exert. about the pressure of the flow line or the discharge on the surface. As understood by those skilled in given material, friction and density also provide hydraulic load and resulting mechanical load, when they are involved in producing pumps through tubular pumping systems such as those contemplated by this invention. It is considered that the friction losses are of a mechanical nature, due to the natural increase resulting in the pressure, by the circulation of the fluid through the pipe; these values vary according to the characteristics of the fluid, such as the viscosity, the tubular dimensions and the flow rates of the pump. By calculating the density of the fluid, the specific gravity or weight of a fluid column is obtained. The setting of values by means of calculations of the density of the fluid allows the aspect of the expert system of the present invention to mathematically establish the increased hydraulic loads and the impact of buoyancy on the suspended suction rods. As will be apparent to those skilled in the art, these values are needed to accurately calculate the impact of the system variables, and to make corrections in order to allow mechanical and fluid level interpretations to be made correctly. The variables that have to do with time and that are used in the computer system and are pointed out in the present invention define a predictable mechanical relationship. In fact, these relationships indicate the possibility that adjustments are required in the operating conditions of the pump or in the dynamics of the well. Additionally, these value-time relationships provide historical data to be used in the analysis of pump and well conditions, preferably on a real-time basis. As experts in the field will notice, these analyzes define eventual characteristics that can then be stored and used by the Expert System to control, optimize and predict the required adjustments in order to guarantee optimal pump performance. Of course, these events also indicate the service demands and other needs of the pump system. Thus, the present invention offers the operator the possibility of effectively increasing the productivity of the well, reduce idle time, and substantially improve the economy of the operation. The present invention also refers to issues of equipment sizing, which prevail in the oil field. In particular, the size of the pump and the type of elastomer are determined based on the pressure and production requirements. The selection is based on the chemical affinity of crude oil with the available elastomers. As examples, elastomers having low gas permeability or aromatic hydrocarbon resistance or higher maximum temperature capacities can be selected. Likewise, the sizing of the head is carried out based on the maximum load supported by the axial bearings and the mechanical power requirements. The mechanical loads are determined by the hydraulic requirements of the pump and by the weight of the rods. The selection of the motor is based on the maximum power required by the pump. The dimensions of the rod string are based on the depth, viscosity of the fluid, API gravity, torsional load, etc. Another aspect and advantage of the present invention is the rule module 23, which is based on experience, for an optimized operation. This type of rules collection preferably comprises a dynamic knowledge base that is derived from the experience in the oil field, to optimize production and reduce the chances of failure. The information in real time, constituted by the variables in the field, including axial load, current motor temperature, head pressure as well as rpms, torsion, etc., is communicated to the software aspect of the present invention through a platform communication standard. As will be described later, the raw data is analyzed in order to decide the correct control action to follow. As will be obvious to those skilled in the art, such actions include changing the speed of the pump (RPM) or changing the percentage of opening of the bypass valve, stopping the pump and system alarm, etc. It will be noted that the objectives of the optimization are: the achievement of a continuous and uninterrupted production of the well; the prediction and correction of situations of malfunction; the reduction of operating costs; prolong the life of the equipment to the maximum, protecting them or modifying the operating conditions. . As will be apparent to those skilled in the art, the diagnosis provided by the present invention (see FIGURE 6) is accomplished by an integrated and iterative process of pattern recognition, using a variety of artificial intelligence tools including neural networks, genetic algorithms. , fuzzy logic, expert systems, etc. Thus, the in-line closed-loop optimization contemplated by the present invention depends on certain variables that must be automated in a well with pump of progressive cavities, such as: the axial load of the system, rotor RPM, motor current, stop and automatic alarms, control of injection of chemical products and diluents, temperature of the motor winding. According to the practice in the field, the. Production engineers must maintain the axial load value within an operating band by oscillating around a design value. This design value is determined from the weights of the rods, the pump and the fluid column within the pipe, also taking into account the minimum level of submersion of the pump. The minimum submersion level of a pump is the lowest level of fluid that can be allowed in a well for maximum fluid production without causing any risk to completion of the well. The present invention makes it possible to easily diagnose important events such as vacuum pumping, gas jamming, excessive torsion, fractures of the rod string, wear on the pump elements and stator dilation. It will be understood that progressive cavity pump systems are based on a rate of production directly related to the speed of the pump (rotor). 'This speed is the same as the spindle axis. Therefore, by measuring the system RPM, it is possible to perform a control action that optimizes the production with the help of an axial load. The system explained by the present invention automatically adjusts the RPM, according to the requirement. Once the RPM has been adjusted, the system checks to make sure that the correct adjustment has been completed. The present invention contemplates the possibility of using any of several different ways to achieve the measurement of the RPM, including magnetic collection, connection in series with a variable speed pulse, etc. By measuring the motor current, the present invention can advantageously perform several operational analyzes, such as: prediction or detection of mechanical load conditions, pump clogging, pumping of solids, gas, etc. The values of the motor current also allow monitoring the system's electrical system, in terms of balanced loads, loss of the phase, etc. Obviously, in certain circumstances it is necessary to stop the system as soon as possible. In general, these conditions can include situations of excessively high pressure in the wellhead, too much torsion (current), extremely high or low axial loads, etc. Consequently, the means are needed to achieve an immediate and automatic stop. Preferential alarms can be provided that warn about potential problems in the system.
By monitoring the flow rate and pressure, the convenience of controlling the volumes of chemical products or diluents introduced into the hole or flow line of the well has been determined. According to industry practice, chemicals may be necessary to prevent corrosion, paraffin accumulations, etc., and diluents are used to control the viscosity of the well fluid. These injection controls can manage the production rate of a chemical injection pump or the percentage of opening in a valve for the injection of chemical products or diluents. To achieve these controls, a means is needed to adjust this valve which could be a valve actuator. The instrument system conforms to any other instrumentation generally used in applications related to oil wells. For example, it complies with the standards of the Instruments Society of America (ISA). Likewise, the present invention also accepts other designs. The aspect concerning the expert system (system"Master" of computing) of the present invention, performs real-time analysis hitherto unknown in the industry (see FIGURES 5 and 6). The behavior of the bottom pump is diagnosed in relation to the axial load. Now it is possible to measure or calculate the runoff of the pump during the operation, and then compare this runoff with an empirical value or with a theoretically calculated value, to decide if the pump has suffered wear or not. This is achieved to greatly improve the preventive maintenance and prediction, as noted by experts in the field. The present invention allows to protect the entire system of the pump from being operated under extreme conditions such as excess torsional load, overload and underload, also making it possible to quickly detect system failures such as fractured rods, leaks in the flow line, obstructions or dilatation of the stator, while allowing the monitoring of fluid level and flow rate objectives. By calculating and monitoring pump inlet and discharge pressures in real time, and by measuring fluid gradients and fluid levels, the pump speed can be adjusted automatically to track a particular fluid level or a correlated flow rate. As part of the present invention it is revealed that said calculations can be carried out by the expert system or selected by the user. As will be understood by experts in the field, the pump rotor RPM constitute a very important variable to control in the system contemplated by the present invention. In order to control the production rate and the level of the gas and oil fluid, a means is needed to adjust the RPMs. It is definitely important that the applied control method complies with the standard and prevailing protocols for instrumentation communications, for example, Modbus RTU, Modbus +, TCP / IP, 4-20 mA, etc.). Some of these devices are the variator of speeds, the system of pulley with servomotor, etc., or the system of pulleys with servomotor commonly used in the industry, that is to say, the mechanical device variator of speeds, in which the servomotor adjusts the speed obtained from pulleys of variable steps. This is how the developed expert system appropriately modifies the speed of the pump to improve its operating conditions. Then, the system waits for the well to recover, depending on the completion dimensions, the latter, the flow rate, etc. During this recovery period, the instrumental system does not provide any calculated dynamic information, because the well is unstable and any calculation would therefore be inaccurate. However, the present invention continues to provide the measured information, and the basic rules of control continue to make the system work. The expert system disclosed by the present invention provides control rules that suggest the potential failure of the pump potential and the well conditions, and provides alarms and even stops to prevent damage to the component costs of the pumping system. It also provides explanatory messages and related information to the well operators, describing the productivity of the well and the behavior of the pump, preferably in real time. As will be specified in detail below, the expert system contemplated in this invention preferably uses fuzzy logic to generate a unique set of operating parameters for each oil field application, and collects and analyzes the historical data for turn them into a knowledge base of the pump and well. The present invention also exploits self-generated parameters, in order to provide to the practitioners of the field a dynamic knowledge base having a data ary of the behavior of the pump and well and to be continuously updated. In this way, the expert system explained in the present invention, provides to those who practice the practice, a novel synergy in which it is possible to inherently improve an already complete analysis, thanks to all the previous analyzes and recommendations are also incorporated there for later analysis and recommendations. As will be described later, this ability to analyze and recommend, characteristic of the present invention, can be interconnected with, or transferred to, other well applications, thus enabling maximum optimization to be achieved in the minimum amount of time. Once the expert system of the present invention establishes sets of rules from a knowledge base, these rules can then be applied to other wells. The expert system can be configured so as to communicate via interface with any standard automation scheme in force in the industry. As the experts in the field will notice, a large amount of analysis and data entry is provided, to be used in the evaluation of the behavior of oil well equipment and the like. It will also be noted that the incorporations of the present invention have been developed to analyze values of analog systems for various components that integrate the electromechanical impeller system of the surface, corresponding to the progressive cavity pumps. As will be described in more detail below, the mechanical relationships for these analog values are developed to form suitable mathematical algorithms, which are used in the generation of useful values for the dynamic conditions of the pumping. The computer system explained in this invention processes and records these values, hence the analysis in real time. An advantageous feature of the present invention is that the well adjustments are made continuously. The preferred embodiment of this invention presents these values and analyzes in a friendly interface between computer and user programmed in Visual C ++ to be used in the Microsoft Windows environment. Therefore, it will be evident to those skilled in the art that the technology to find these analog values, as well as the methods of analysis and the designs of the computer system, had not been known up to now as far as the actuator systems are concerned. Progressive and similar cavity pumps used in oil production and recovery operations. That is, practitioners in this field have used hole-bottom pressure transducers, connected to a processor on the surface, or connected to a dedicated sonic device, to determine the fluid level information in real time. But these conventional systems are not only comparatively expensive but also provide limited capabilities since they only allow the analysis of a single variable indicative of fluid level.; these systems inherently suffer from a lack of capacity to correctly diagnose the dynamic conditions of the pump and to provide an expert system to optimize their behavior, as contemplated in the present invention. With reference to FIGURE 5, a General Loop 300 of the present invention is described, which functions as a closed loop for automatic control in the PLC. According to what will be described later in greater detail here, the General Loop 300 comprises the steps of exploring the variables that include the inputs and analog parameters 310, then diagnostic procedures 320 for the optimization as contemplated by these descriptive memories, and a procedure to report the variables 330 to the Master Expert System or to the SCADA System. Referring now to FIGURE 6, the steps that make up the diagnostic procedure 320 are appreciated in it. In particular, certain rules are observed, namely Rule 1 (340) and Rule 2 (350), and certain analyzes are performed , that is to say, Analysis 1 (360) and Analysis 2 (370), which are executed successively as will be described later, to evaluate in a total and dynamic way the conditions and the operational behavior of the pump. The exploitation of the logic and several functions of the expert system incorporated in the present invention requires establishing a methodology contrary to what has been done up to now by the operators of the industry. It will be noted that the concepts and underlying logic are based on the premise of a determined principle from exhaustive laboratory and field tests: it has been found that a functional relationship between the axial load and the level of the fluid presents a precise and uniform behavior when it is correctly adjusted with respect to the cumulative effects of all the variables that effect this functional relationship. As an indication of the efficiency of the computer system explained in this invention, the relationship, as developed by the instrumented expert system, can be and has been expressed as a simpler equation that can be normally provided by those skilled in the art. As a prerequisite to the procedure, a series of steps must be followed in order to properly initialize the application of a particular oil field. During the calibration of this application, the initial fluid levels are obtained from sonic level tests or other known methods. As understood by experts in the field, at this time the fluid level and the axial loads become known values. Then, several fluid level tests are performed at different fluid levels to properly characterize the functional relationship between the axial load and the fluid level. The expert system of the present invention then generates a polynomial equation to represent this fundamental relationship. It has been found that the appropriate formula can be determined effectively using conventional linear regression. Of course, it may be convenient to calculate the impact on the relationship between the axial load and the fluid level that other variables exert, with the polynomial equations generated during this calibration step. A feature and advantage of this invention is that the ability of the present computer system to perform these self-generated polynomials and actual values calculated for the fluid level improves the confidence in the values of the fluid level, per se. The present invention has fulfilled this intimidating and multifaceted task of collecting data in real time and its respective processing and analysis, together with the consequent adjustments in the operation of the pump, in a way previously unknown in the industry. As will be understood by those skilled in the art, the present invention exploits the ability to obtain the suction pressure from the axial load supported by the head. More particularly, the level of total fluid, derived from the axial loads supported by the bearings arranged in the head, can be represented by the following expression: Wr + Rp + (Pwh + Ps + (LrGs) (Ar-Ar) -PcAR -The LVLS =ARGs where LVLS = Fluid level -feet (calculated) La = Axial load- pounds (measured on the load sensor) Wr = Weight of the Rods on the Fluid-pounds (Calculated) Rp = Rotor thrust - pounds (calculated) PWh = Wellhead Pressure - psi (measured) Ps = Friction Pressure - psí (calculated) Lr = Rod Length - feet (measured) Gs = Fluid Gradient - psi / feet (calculated) AR = Cross Section Pump Rotor area-in2 (measured) Ar = Cross-section of the Rod-in2 area (measured) Pc = Pressure of the coating pipe psi (measured) It has been found that knowing the dynamic level of the fluid in a well in operation, allows an invaluable appreciation of the behavior of the pump. In fact, the dynamic level of the fluid allows to observe in real time the relationship between the pumping speed and the productivity of the well, where the behavior of the pump can be monitored and maximized to achieve not only optimal gas production or oil, but also the completion of wells and extensive knowledge of the conditions of the deposit. It will also be noted that, the value of the fluid level, in comparison with the theoretical capacity of the pump, also suggests the condition and behavior of the pumping system. As with any pump, as the bottom pump wears, operational efficiency decreases. In conventional bottom pumping operations, the pump's output is manually adjusted by appropriately varying the pump's RPM to try to keep the productivity of the well to the maximum. Experts in the field should clearly see that without an understanding of the conditions of the well in real time the analysis of the well and the behavior of the pump is a task that takes a long time and requires a great effort. From the point of view of the advantages, if one does not have the benefit of automated analysis in real time, as provided for in the present invention, the only realistic way in which the operator can detect the need to change the production requirements of the pump, is through a catastrophic reduction in well production. Generally, to obtain the dynamic level of the fluid, the well operator must periodically use a sonic test of fluid level, which is both costly and inconvenient. However, due to the problematic and expensive nature of these tests, the well operator usually makes an estimate of the production rate, in an attempt to achieve maximum well productivity. In addition, there is a serious possibility that oil well productivity will be adversely affected by too low fluid levels. Understandably, this known and potentially disastrous consequence makes the operator adopt a conservative attitude, reducing the probable maximum production of any particular oil well. Likewise, as is well known in the industry, pumps are used in gas wells to release the back pressure in the formation, extracting the fluid from the well. The back pressure generated by the fluid inside the well reduces or stops the production of gas. Bottom pumps are usually placed under well boreholes to reduce fluid level until gas flows from the well. The usual thing is that the well continues to flow until the backpressure occurs again due to the continuous entry of water into the well. Accordingly, according to the present invention, adequate design parameters must be established to correctly configure the various components of the integrated computing system, in order to be able to monitor the behavior of the real-time pump and achieve the optimization of the pump under the influence of an automated expert system. The aspect of the optimization, corresponding to this invention, has been divided into two primary control units. A) Yes, the preferred embodiment is configured using a primary control system comprising the advanced ACU control unit. It will be noted that the primary function of the ACU is to provide a detailed assessment of well operations, contain the expert system and evaluate the stored data obtained from a local controller placed locally at the well site, that is, obtained from a PLC or from an RTU unit. The PLC / RCU thus provides local control of the expert system disclosed herein, by accessing a set of dictated variables, either by loading from the ACU several corresponding values, or by manually programmed values during the assembly and installation of the system. These two control units explained in the present invention require different design parameters. The ACU unit, functioning as the "brain" of the system, interacts interactively with the operator / user and requires a lot of programming. As will be described below, several objects comprise the computerized optimization system, and either perform a particular function or constitute a prerequisite for recursive human interaction. Contrary to what happens with the ACU unit, the PLC / RTU of the present invention, usually requires a simpler programming. Of course, the RTU unit is programmed during assembly and during operation using the values obtained from the ACU unit.
It will be noted that in the preferred embodiment, the software applying the ACU unit requires substantial inputs by the user, due to the elements naturally required in relation to the well sites, as well as to achieve the monitoring and behavior of the well. pump, detailed and robust, which contemplates the present invention. This diversity of input variables (and their resulting associated calculations) and interrelationships, establish the functional basis for the modules of the underlying computing program and for related objects, as will be described later in detail. The enumeration of elements that follows corresponds to both the inputs of the user required, and the calculated values. It will be understood that many of the user's entries t are pre-programmed in the software as a user interface for data entry. For example, such pre-programming of user inputs would occur if it were known that the variables are standard and acceptable in the industry. On the contrary, other variables that are a prerequisite, require that the end user provide design details necessary in order to make available all the capabilities contemplated in the automated system according to this invention. Of course, it should be obvious that the following elements only represent the basic definitions of objects and forms of input for computer programs that implement the preferred embodiment. In many practical applications, polynomial linear regressions are used in software to establish exact values derived from verified field tests, and are indicated by their elements. The use of these pre-required elements is illustrated by the pseudocode described below. In addition, the integration of these elements and objects, and related calculations, can be quickly appreciated in this pseudocode. For convenience, the items listed below with no comment attached generally refer to user or programmer entries; the elements are categorized within their intended objects that are contemplated in the preferred embodiment, which is carried out in the C ++ language. It will be understood, of course, that the implementation can be carried out in any suitable programming language, in any sufficiently powerful and versatile computer, either portable or desktop. The design objects of the ACU, include the well object, bomb object, rod object, complementation object of the well, head object, surface motor object, gas segregating object, reservoir object, communication library object, production pipeline object, Coating pipe object, object flow line, gas separator object, object load sensor, object protocol, object surface equation, object variable frequency controller, object background equipment, object pump optimization system, object head, object Automation equipment on the surface, object coupling, object rods section, object rods continuous. The elements and behavior of the well object are discriminated in the following way:. id name of the well static fluid level: calculated by static pressure: static bottom pressure: calculated by the static fluid level • well flow pressure: calculated by the formula pwf = (depth of perf ^ specific gravity oil * gradient water *) + wellhead pressure actual production rate: calculated by the operational rate of the pump; formula to be described below desired rate: maximum rate: calculated using Vogel & Darcy standard equations, well known in the oil industry, to evaluate the behavior of the incoming flow. If the productivity index, pi = 0; If the bubbling pressure point > static pressure - > Vogel If not permanent (Vogel or Darcy) If not through the productivity index and the static pressure (line equation since the curve pi is a straight line) bottom temperature head temperature well productivity index: pressure point borehole pressure bubbling: Measurement in real time operation calculated by correlation of the gas separator.oil gas ratio: calculated to compensate in real-time operation wor (oil water ratio or percentage of water) oil gravity API specific gravity of gas salinity of water percentage of H2S bottom viscosity well head viscosity percentage of aromatic presence of sand maximum operating speed minimum operating speed dynamic fluid level: calculated by measurement of load sensors in real time operationload sensor-buoyancy factor measurement * weight of rods (air) whp + fl Fl = - pump constant * area of the botcba * gradient of fluid gradient of fluidcalculated with the inlet or discharge pressures of the pump and the Delta P. operating pressure of the well: measured by the load sensor meter multiplied by the pump area, results in the Delta P of the friction losses of the pump in the pipeline: calculated by: A = pow ((0.292 * q0), 1.85); (3)B = pow (d, 4.8655); (4)Tf = .18 * (length of pipe or depth of pump / 100.0) * (a / b): (5) fluid gradient; calculated by linear regression of the practical empirical curve at the time of start up volumetric factor: calculated by radius correlation of the well horizontal radius of the drainage factor. buoyancy: determined in the starting procedure via linear regression vplumétrico factor of the casing formation: see definition of casing The elements and behavior of the PCP bomb object are discriminated as follows: make: model: maximum rate @ height 0 @ 500rpm maximum height: maximum rate @ Max. @ 500rpm rotor diameter eccentricity hp @ height O @ 500 rpm hp @ Max. @ 500 rpm number of steps operating delta pressure: calculated by load sensor measurement Load-Buoyancy Factor * Weight of Rods DeltaP = (6) Pump constant * Pumping Area pump inlet pressure: calculated by correlations based on the calculated fluid level, that is, based on the underlying design process calculated by correlation based on DeltaP, and the head pressure of the pump attachment depth: minimum submersion of the pump Operating RPMs: calculated by parametric function depending on the operative DeltaP and the real or desired rate: vb = qmax5 / 500; (7) aa = (qmax5-qapmax5) / po (pmax, 2); (8) Rrpm = ((qmax poz + aa * pow ((2,308 * DeltaP), 2)) / vb); (9) operating regime: calculated by the delta pressure of the pump and the operating rpms; verified by measuring the presence of elastomer fluid: determined by the conditions of the well, Eg; aromatics, sand, etc. constant k for the pumping area minimum starting torsion The behavioral elements of the rod object are discriminated as follows: friction losses on the rods: calculated by correlation diameter roughness factor linear weight weight weight in the air The elements and Completion object behaviors are discriminated as follows: drilling depth vertical depth total casing pipe production pipe rods flow lines true vertical depth of each piece the elements and behavior of the head object are discriminated as follows: make: model: recommended by the computer program through the maximum axial load to be generated by the maximum axial load system hp maximum rpm maximum minimum rpm The elements and behaviors of the gas segregating object are thus discriminated: efficiency The elements and behavior of the surface motor object are discriminated as follows: make model size: calculated by the computer program through the maximum hp to be handled by the head hp maximum temperature maximum current maximum actual temperature: measured by the temperature transmitter actual temperature in operation: measured by ammeter in one of the phases Motor condition equilibrium: calculated by the value of the current in all phases The elements and behavior of the reservoir object are discriminated as follows: name field geographic direction constant reservoir constant vertical permeability constant horizontal number of wells elements and behavior of the communication library object are discriminated as follows: hardware platform protocol (layers of the operating system model, serial port, network port) configuration The elements and behavior of the production pipeline object are discriminated as follows: number of sections internal diameter external diameter factor of roughness density of linear weight length of the section The elements and behavior of the pipeline object of coating are discriminated as follows: number of sections internal diameter factor of roughness density of linear weight length of the section The elements and behavior of the object flow line are discriminated as follows: length internal diameter pressure drop: calculated by the program through the pressure of the gas separator and the pressure of the well head calculated having one of the above and using the correlations. roughness factor average angle from the horizontal (ascending "+", descending "-") with the vertices in the well head The elements and behavior of the gas separating object are discriminated as follows: volumetric capacity separation pressure actual pressure temperature: measurement through the pressure transmitter The elements and behavior of the load sensing object are discriminated as follows: total area to load hydraulic fluid pressure: measured by the pressure transmitter in the load sensor total axial load: calculated by the pressure of the hydraulic fluid multiplied by the total area to load maximum axial load that can be measured: calculated by analysis in the load sensor the elements and behavior of the protocol object are discriminated as follows: • communication frame configuration error messages error review codes function The elements and behavior of the object eq. of surface are discriminated in the following way: variable frequency driver motor The elements and behavior of the variable frequency controller object are discriminated as follows: input voltage output voltage frequency range frequency step The elements and behavior of the object background equipment are They discriminate as follows: gas segregating pump, The elements and behavior of the PCP System Optimization object are discriminated as follows: well automation equipment on the surface bottom equipment well model PCP The elements and behavior of the head object are discriminated as follows : it is a head but it has a load sensor The elements and behavior of the object automation equipment on the surface are thus discriminated: variable frequency controller alm1 of the head The elements and the behavior of the coupling object are discriminated as follows: external diameter length losses per friction in the couplings: calculated by a correlation The elements and behavior of the object rods of section are discriminated in the following way: friction losses in the rods: calculated by means of the correlation number of sections diameter section length roughness factor linear weight density weight in the air couplings The elements and behavior of the continuous rod object are discriminated as follows: friction losses in the rods: calculated by the correlation diameter length of the section roughness factor weight density linear weight in the air The class relations for a deposit, they are discriminated like this: a deposit has wells The class relations for a well are discriminated as follows:(n de, t,; artificial lifting equipment) one well has an artificial lifting equipment; a well has a surface equipment and a bottom equipment a well has a completion: a well has casing rods, couplings The class relationships for the artificial lifting equipment are discriminated as follows: an AIM1 (head with sensor load) has a surface equipment an AIM has a background equipment Class relationships for background equipment are discriminated as follows: it has a pump has a gas segregator The class relations for the surface equipment are discriminated as follows: it has a motor has a variable frequency controller has a head The class relationships for completion are discriminated as follows: has a casing has a production pipeline-1 (n of, t,; artificial lifting equipment) has rods has couplings has a flow line The class relations for the artificial lifting equipment PCP, are discriminated as follows: it is a team of lev. artif. 'has a PCP pump as bottom equipment has a head as surface equipment The class relations for the pump are discriminated as follows: has a maximum rate has a maximum height has speed Class relations for the PCP pump are discriminated as follows: it is a pump type it has a rotor, it has a stator The class relations for the gas separator are discriminated as follows: it has an efficiency The class relations for the axial load measuring head are discriminated as follows: a type of head has a load sensor The class relationships for a PCP well model are discriminated in the following way: it has basic rules has expert rules The class relationships for a PCP optimization system are discriminated as follows: it has a well Automation equipment on the surface has background equipment has a completion has a well model PCP Class relations for An automation equipment on the surface is discriminated as follows: it is a type of surface equipment but it has a variable frequency controller that has an eq head. of artificial liftingReferring again to FIGURE 4, thePLC / RTU 400 receives four analog inputs through the field instrumentation organizer 10. More particularly, the field instrumentation organizer, receives the analog input of each flow line pressure transducer 15, casing pressure transducer 20, motor temperature transducer 30, and the RPMs provided by the variable frequency controller 60, inverter or a magnetic collector of RPMs. It will be understood that, when using a variable frequency controller or a variator, it is contemplated that the variable will be provided by the Modbus serial port. It will be appreciated that all analog inputs should preferably be 4-20 mA inputs. Therefore, according to the present invention, the RTU unit will simultaneously process the information on the pressure of the process transmitted from each of the load sensors and the head, the information on the current and temperature of the motor and the information on the RPMs. The various variables incorporated in the rules and formulas and in the algorithms explained in the present invention and applied in the preferred embodiment are listed as follows: WHPH: High Range Value for Well Head Pressure. WHPL: Low Range Value for Well Head Pressure. LCPH: High Range Value for the Load Sensor pressure. LCPL: Low Range Value for the Load Sensor pressure. CALC1: Axial Load of the System CALC2: Operating DeltaP CALC3: Weight of the rods CALC4: FLOORABILITY FACTOR CALC5: Fluid Level of Operation CALC6: Nominal Load CALC7: New RPMs Kl: Weight of the Rod String in the Air K2: Friction Losses. K3: GRADIENT OF THE FLUID K: PUMP Area K5: The Optimum Dynamic Fluid Level K6: Optimum Wellhead Pressure K7: Optimum RPMs K8: Maximum RPMs. K9: Minimum RPMs K10: DeltaP of the Desired Pump Kll: Qmax5 K12: Qpmax5 K13: Maximum Height that the Pump can handle K14: Load Sensor area in square inches K15: Maximum Speed at which the K16 well can produce: Step to increase or decrease the RPMs K17: Recovery time that the well must wait while the load returns to its normal band. K18: Nominal Current for Motor or VFC, etc. As will be described later in detail herein, these variables are subsumed to several rules, analyzes and procedures that achieve the advantageous optimization of the pump described in the present invention. The agreement used here to identify such rules, analyzes and procedures is listed as follows. Rule 1: Detection of Fractured Rods Rule 2: Detection of Analytical Current: Analysis of Load Analysis2: Analysis of Wellhead Pressure Procedure: Process to Calculate the Runoff of the Pump Procedure2: Current Detection MATRIX1: Matrix containing the measurement of the Load during the pump run-off process According to the preferred embodiment, the computerized expert system recommends and sets new RPMs. This action can be provided through a Modbus port to a variable frequency controller ("VFC") slave, etc. As previously described here, the 4 to 20 mA standard should be the preferred one. The system will have four digital outputs to activate the automatic shutdown of the pump assembly. It will be noted that, normally, the PLC manufacturer provides a minimum number of digital outputs. of course, this invention contemplates that there must be four of said outputs in order to have enough space for three optional digital outputs that may be needed. Likewise, three digital inputs, corresponding to a "No Operation" condition, an "Engine Reheat" alarm and a "Power or Current Supply" fault alarm must be provided. It should be understood that it is better to reserve a memory space for the constants to be used in the process. Most of these variables are determined during the start-up procedure and can be loaded or eliminated by the Master in the operation. In accordance with the present invention and with respect to scale considerations, calculations are made on the current measurement recorded by the PLC (as analog input), through the following formula: Current Measurement (mA.) Actual value * (HRV-LRV) + 1.25 * LRV-0.25 * HRV (10) 16 where, the Current Measurement is the analog input value; HRV is the high range value; LRV is the low range value. HRV and LRV are constants of the PLC and can be set by the Master Expert System of the present invention and then be input to the PLC. The Axial or Push Load of the System ("AI") must be calculated using the formula: Load = LC-Pressure * LC-AREA (11) or Load = Result of the Extensiometric Sensor where, LC-Pressure, is the pressure recorded by the pressure transmitter (4-20mA) used with a hydraulic load sensor; LC-AREA is a constant determined by the PLC operator. This load value is initially equal to 31.42 square inches. Changes to this parameter should preferably be fixed by obtaining another configuration from the Master Expert System and entering a certain Modbus address. According to the preferred embodiment, the load value of the system is reported to the master through the Modbus port. Pump DeltaP is determined from the following formula: DP = (Load-of-System-Weight-of-Rods) / Area-PUMP (12) where DP is the Pump's DeltaP; Load-of-System is calculated as described above: Rod-Weight = Weight-of-Rods-in-Air * Factor-Buoyancy (13) and the Area-Pump is a constant loaded by the Master Expert System. Those skilled in the art will note that, typically, the Buoyancy Factor is determined by the start-up procedure, based on the RPMs. Thus, in order to know the buoyancy factor, it is necessary to measure the RPM. It will be understood that there is a memory map stored in the PLC to preserve the matrices with the corresponding values for both the RPM and the buoyancy factors. A representative memory map, generated by the PLC of the preferred embodiment is as follows:If the value of RPMs is between values stored in two successive rows of this matrix, a linear extrapolation is then required to determine the value of the buoyancy factor. For example, if the RPM at a given moment is 150, then the Buoyancy Factor (BF) is obtained through the following formula: (0.40-0.43) BF = 0.43 + * (RPMS-100) (14) ( 200-100) Then, the BF = 0.415. In accordance with the present invention, this value is reported to the MASTER via the Modbus port. According to the present invention, the fluid level is calculated by the following formula: (Delta P of the Ecpba-Well Head Pressure-Friction Losses)Fluid Level = Fluid Gradient (15) where: DeltaP-Pump: calculated as described above in these memories; Pressure-Head-of-Well is an analog input; Gradient of the Fluid is a constant to be established by the Master at the moment of the start; Friction Losses is a constant determined by the Master at the moment of starting and can be fixed during the operation. It will be noted that the underlying design of the expert system disclosed by the present invention is based on some theoretical values generated from the formula (1) hereinbefore described. It has been found that the present system can use a polynomial regression formula to offer precise values of fluid level. The limit values for generating this polynomial regression formula are established during the start-up sequence in the field. During start-up, the fluid level is effectively measured, preferably using sonic equipment. The computation system explained in the present invention, evaluates the axial load, the pressure of the flow line, the pressure of the casing and known variables, against the sonic values of fluid level, in order to generate a formula of appropriate regression. The result of this generated formula is compared with the theoretical values derived from the original formula. This error review is used to obtain exact values of the fluid level and relationships with respect to other variables. Once the polynomial formula has been established, exact values of low level are given to the Expert System values and then to the user in the field. It should be clearly understood that this model for the design and optimization of pumps is generated on an individual basis, for each well site. It should also be understood that these multiple formulas and mathematical functions are programmed in both the ACU unit and the PLC / RTU. For an exact fluid level and related information for the duration of the pumping systems contemplated according to the present invention, it is preferable to recalibrate periodically, using sonic measuring devices of the fluid level. As indicated in the present invention, the nominal load constitutes a reference value for the system load and is used when the basic rules are being executed in the PLC. Normal Load-Are efe Ja Et_? ± H * (F -__>) Gra i__tte efe FJi ± bWib € érdicas ppor? ___ xi ??) 4Pe_D efe V ___ ülas (16) where: Area-Pump is as previously described here; Fio is the optimum fluid level, which is a constant determined by the Master at the time of starting and which can be set under normal operation; Gradient-Fluid, is as previously described here; WHPo is the optimum well head pressure, considered as normal under operation, which constitutes a constant to be determined by the Master at the time of start-up and can be changed during the operation; Friction Losses, as previously described here, Rod Weight, is as previously described and corresponds to the buoyancy factor calculated using the RPMo value to correlate; and RPMo are the optimum RPM which constitutes a design constant established by the Master at the time of start-up and which can be set by said Master during the operation. In relation to the system RPM parameter, there are two constants to be set at the moment of start-up, and fixed during operation: MAX-RPM specifies the maximum of RPMs allowed by the pump system and MIN-RPM specifies the minimum of RPMs for operation. It will be noted that the minimumRPMs during normal operation of the pump is zero. The formula for the RPMs is: Qmax + A * (2,308 * DP) 2 RPM = 500 * (17) Qmax5 where: Qmax is the maximum possible speed for the pump system, or is another possible value to be set by the Master , and remains constant under normal operation; DP corresponds to DeltaP-de-la-Bomba-Deseado, which is the value for the DeltaP that the rules of the present invention are recommending at once - this value can be determined either through a rule or by the Master Expert System; Qmax5 is the maximum speed that the pump can handle when it operates at 500 RPM @ zero height, and is a constant determined by the Master at the time of start-up; A is a factor determined by the formula: (Qmax5-Mpmax5) A = (18) Pmax2 where: Qpmax5 is the maximum speed that the pump is capable of handling when operating at 500 RPM @ maximum height, and is a constant determined by the master at startup time; Pmax is the maximum height of the pump, which is a constant determined by the Master at the time of starting. It is contemplated that the value of the RPMs according to the preferred embodiment must be set by the Modbus port as a new frequency value. The experts in the matter will notice that, for each controller of frequency is determined (VFC), the new frequency is determined by formula, based on the requested RPM; optionally, it will be an analog output of 4-20mA. In both cases, the fixation point may vary depending on the way in which the Slave device used to adjust the RPMs understands the command, whether it is a new fixation point, or a certain increase or decrease in the value of the current. . If there is an increase or decrease in this value of the current, it is necessary to know the current RPMs in order to know their differential value. The application of this diversity of objects and variables can be conveniently illustrated using a pseudocode. For example, the aspect relating to the load analysis of the present invention, considers all value for the load between the Limit-Normal-High = 0.85 Load-Nominal and the Limit-Normal-Low = 1.15 * Value-Nominal, as normal. Therefore, for the loads located within this comfort zone, the present invention does not generate any alarm. However, the alarm is activated for events that occur outside this zone: Exceeded the Normal-High-Limit: accountl = accountl + l if the account > 3 Stop and Restart account Generate Alarm and Exit Loop if not Decrease RPMs Wait for Recovery Time Limit-Normal-Low: account2 = account2 + l if account2 > 3 Stop and Restart account Generate Alarm and Exit Loop if not Increase RPMs Wait for Recovery Time Continue PLC General Loop It is to be noted that, within this loop, the increase inRPMs is a constant to be set by the Master at start-up, and can be modified during normal operation. The Recovery Time contemplated by this invention is a period during which the load will be measured but in which the event link will not be executed again.
It should be evident, that this procedure is observed to allow the pump system to recover from the new fixation point of RPMs. Once the Recovery Time has expired, it is obvious that the event loop will be executed again, if another Limit Violation occurred, even though the normal scan for the PLC is not interrupted by that event. For normal operation, the startup of the computer system explained by the present invention is first configured by setting the values for each constant or parameter required by the PLC to execute the logic contained in the General Loop (see FIGURE 5). These values include HRV, LRV and Weight-of-Rods-in-Air, which are listed as follows: HRV: High Range Value for the analog inputs. For the Load, the HRV is given by the formula: HRV = 1.5 * (Weight of the Rods in the Air * Buoyancy Factor @ O RPM + (Depth-Setting-Pump * Gradient-Fluid * Area-Pump)) (19 ) LRV: High Range Value for analog inputs. For the Load, the LRV is given by the formula:LRV = (Weight-in-Air-of-Axis-Head) (20)Weight-of-Rods-in-Air: free weight of rod string.
It should be noted that the HRV and the LRV for the head pressure transmitter can be set by the Master during this starting procedure. It is expected that a memory area will be established in the PLC to incorporate all these constants. In accordance with the present invention, a memory map must also be generated at the time of startup, to determine the frotability factor, depending on the RPMs. An Echometer or Sonolog system helps to make this determination, in order to obtain an approximation of the fluid level. It has been convenient to carry out several tests -from 0 RPM to reach an adequate calculation of the Buoyancy Factor: (LC-Area of the Pump * (FL + Pressure_head_Pound + Loss_Friction)) Bfx = * X RPM Weight_of_Varilla_en_Aire (21)where: BFx is the Buoyancy Factor @ the RPM X; FL; is the fluid level registered by the Echometer or Sonolog; and the rest of the variables are already designated. Then, a memory map must be established in the PLC, so that the Buoyancy Factor can be determined whenever this is necessary for the behavior and optimization of the pump contemplated by this invention. Another variable is the fluid gradient, which constitutes a constant to be determined during the dimensioning or design phase of the well. According to the practical experience of the operator, the Fluid Gradient should generally be considered constant. But the variations in the axial load caused by the free gas compressed in the fluid column of the pipe, should not be very high, thanks to the light weight of the free gas. Experiments in the field have frequently supported this theory. The Pumping area is a variable that corresponds to the pumping area considering the effect of the rods. FLo is the value of the optimal dynamic level of the fluid, which is preferably determined by knowing the value of the desired rate. Then, using the behavior curve of the pump illustrated in FIG. 12, and with the values of the desired RPMs, the height of the pump is calculated, that is, the pump's DeltaP. Once the pump's DeltaP has been calculated, the optimum dynamic level of the fluid can be determined:FLo = DeltaP-Pressure_Rob_Heavy-Losses_Friction Gradient_FluidDeltaP_Pression_Pole Head-Losses_Friction FLo = (22) Fluid GradientSimilarly, WHPo is the optimum well head pressure that is considered normal under operation. This pressure is usually determined by the Gas Separator and correlated after the pressure with the well head. If the well is old, then the WHPo can be set by the operator. RPMo is the optimum of RPMs that is determined from the knowledge of the optimal FLo or the optimal DeltaP: Qmax + A * (2,308 * DP) 2 RPM = 500 * (23) Qmax5 MAX_RPM is the maximum of RPMs permissible for the system ' the pump, whether it is limited by the VFC2, the head, or by the well operator. MIN_RPM is the minimum of RPMs allowed for the pump system. DeltaP_de_la-bomba-Desired, is the DeltaP in the pump to produce the desired production rate @ the desired RPM, and is determined based on the curve of the pump. Although, as will be understood by those skilled in the art, all the desired RPM values are ideal, said values are necessary for the start of the system. The variable Qmax5 corresponds to the maximum speed that the pump can handle when operating at 500 RPM @ zero height. Equally Qpmax5 corresponds to the maximum speed that the pump can handle when operating at 500 RPM @ maximum height Pmax is the maximum height that the pump is capable of handling. Obviously, it should be clearly understood that this start-up procedure must include the calculations of the values for each and every one of the variables or constants described herein. These calculations are based on the information provided by the well operator, the maximum rate, API gravity, etc. One consideration that is related to the start, is the calculation of the push load of the rods. The Push Load of the Rods is the load that causes the rod to stretch when the pump starts to work. Although there is no known reliable way to determine the RPDL, with some practical assumptions, it is possible to measure this value. According to the preferred embodiment, the reading of the Echometer is considered as a measurement of the true thrust load, and consequently, the fluid level calculated with the axial load will be corrected accordingly. In general, it has been found that the fluid level measured with the axial load is lower than the Echometer measurement. If, at any time, the reading of the Echometer is EFL, and the reading of the Axial Load is AFL, then a correction number will be determined by the RPDL-: RPDL = (EFL-AFL) * GRADIENT__FLUIDO * AREA_BOMBA (24) It has been found that, to ensure that the behavior of the pump is being properly monitored and optimized, it is necessary to measure the RPDL at the time of start-up and at a rather low speed, for example, less than 100 RPM, to ensure that the highest value is taken . In this invention, the Expert System takes into account the fracture of these rods, through the Rule of Fracture of Rods. In particular, If the System Load <Weight of Rod String in Air * BF @ 0 RPM2 (number of t .: frequency converter) Stop and Generate Alarm and Exit the Loop. It should be understood that the buoyancy factor, BF, used in this correlation, is calculated at 0 RPM to ensure that there is indeed a case of fracture. For a Pump Runoff condition, the Expert System proceeds as follows: If Not Stopped While the Load_of_the_System > 0.85 * Nominal_load or Time_Transcurred < 30 seconds Continue Load Measurement Load Load and Start Time Loop Exit Process The following pseudocode illustrates the Expert System procedure for detecting current: Exceeded Limit-Normal-High: Stop and Generate Alarm and Exit Loop-Limit Loop-Normal -Low: Stop and Generate Alarm and Exit Loop Loop Unbalance Situation Stop and Generate Alarm and Exit Loop Loop Fault in Power Supply Stop and Generate Alarm and Exit Loop Loop Referring now to FIGURE 5, algorithms appear there control and optimization disclosed by the present invention. With respect to the axial load, Max. It is the Load value at the stop point due to overload Min Load. It is the value of the load at the stop point due to underload. DV (Design Value) is the load at which the well is in normal conditions and is producing at its optimum rate. Decreasing RPM corresponds to the conditions under which the system will automatically reduce the Pump RPM until the load value is within the normal operating range. This usually corresponds to 1.1 * DV, where the client makes the selection with the recommendation of the expert system. Increasing RPM corresponds to the conditions under which the system will automatically increase pump RPMs until the load value is within the normal operating range. This normally corresponds to DV / 1.1, where the client makes the selection with the recommendation of the expert system. The load values are compensated for by the impact of factors that affect the hydraulic loads, such as the pressure of the flow line, the pressure of the casing and the mechanical friction in the bottom elements. Under normal operating conditions, the axial load must remain within its band once the system has reached the RPM at which the fluid level objective is achieved, and speed variations may occur according to variations in the load. The Maximum Axial Load corresponds to the conditions in which the differential pressure of the pump is high due to a low suction pressure of the pump, suggesting that the production rate of the pump is too high. The RPM is reduced until the axial load returns to normal after the recovery time. Various adjustments are attempted, t whose number is preferably selected by the user. If the system does not recover, a stop command is generated. The Minimum Axial Load corresponds to the conditions in which the differential pressure of the pump is low due to a high suction pressure of the pump. To increase the axial load there are increases in the speed of the pump. If this fails, after several attempts, a stop is generated. If the axial load reaches a value below the Minimum Load, referring to FIGURE. 5, a case of fractured rods is detected, and a stop command is generated immediately. The Well Head Pressure, Current, Temperature Analysis, correspond to the conditions under which a Stop command or an alarm is generated. When any of these variables exceeds the minimum or maximum selected. It has been found that there are general and advantageous "tips" for the application of the PLC Rules described here. First of all, the command to Increase or Decrease RPMs of the Expert System can be canceled by the Stop command, but the opposite is not possible. Second, the PLC will continue to run the Pump Runoff Procedure, at the request of the Master. Then, all the constants of the computer system, analog inputs and outputs, digital inputs and outputs, and calculations directed to the steps (variables calculated in formulas of PLCs or Rules and procedures) must be recoverable and be able to be set by the Master Expert System or by a SCADA system, at the request of the operator. In addition, upon detecting any of the three digital input alarms described above, the system explained will be Stopped, and the alarm will be generated for the Master to recover it the next time he requests an Information Record. According to the present invention, two analyzes of WHP, upstream of the throttle and down, proceed as follows: Loop Measure all the variables Si (Head-of-Well-Ascending Pressure = Well-Head-Pressure-Descending ) Proceed to Regular Analysis If not Yes (Head-of-Well Pressure2 IS Normal) If (Head-of-Pozol Pressure is Low and Load isHigh and Normal Current) Release Gas through Pump and Decrease RPMs If (Head-of-Pozol Pressure is Low and Load is High and High Current) Saw Through Pump and Decrease RPMs Yes (Pressure-Head-off) Well 1 is Normal or High and Load is Low and Normal Current) Well-Flowing Naturally, Stop and Report Yes (Head-of-Pozol Pressure is Normal or High and Load is High and Normal Current) Well is losing Fluid Level and Decrease RPMs from where, the Pozol-Head-Pressure corresponds to PRESS-HEAD-OF-WELL-DESCENDANT and Pressure-Head-of-Pozo2 corresponds to PRESSURE-HEAD-OF-WELL-ASCENDING. It will be understood that the Recovery Time contemplated by this invention is the time a well needs to respond and stabilize when it is supporting a change in speed. Therefore, the Recovery Time is defined as that necessary to move the entire fluid column above itself to the flow line of the surface. According to the preferred embodiment, this time is calculated as follows: Volume of Fluid Column (Barrels Recovery Time = Daily production (Barrels) (25) 3, 14/4 (D.1 of the Pipe) 2 * PSDDaily production (Barrels) 86,400 seconds. Other correlations included in the preferred embodiment comprise, on the basis of the variables and parameters previously listed here: CALC1 = AIXK14 (26) CALC2 = (CALC1-CALC3) / K4 (27) CALC3 = K1XALC4 (28)For CALC4, the memory map illustrated above will be used to determine the value of this variable. In practice, the map preferably consists of two matrices of 10 values each. As the experts in the field will understand, there is a corresponding relationship between each member of the first and the same member of the other. Depending on the value of INPUT1, there is a different CALC4. That is, to know the value of CALC4, it is necessary to measure INPUT1. If the value of INPUT1 is between two of the same matrix, then a linear interpolation is performed to determine the value of CALC4. For example, if the INPUT1 is, at a given moment, 150, then it is determined that CALC4 is 0.43+ (0.40-0.43) / (200-100) * (INPUT1-100) 0 0.415. CALC5 = (CALC2-AI2-K2) / K3 (29) CALC6 = K4 * (K5 * K3 + K6 + K2) + CALC3 (30) where for CALC3, in this context, the Buoyancy Factor is calculated using the value K7 instead of INPUT1. K15 + A * (2.308 * K10) 2 CALC7 = 500 * (31) Kll where A corresponds to a factor determined by K11-K12 A = (32) K13 It will also be understood that the value CALC7, as a new value of RPM or frequency , must be set by the Modbus port or through analog output (AOl). According to the present invention, there is a formula for each VFC to determine what the new frequency will be as a function of the requested RPM. Optionally it will be a 4-20mA analog output. In either case, however, the fixation point may vary depending on how the slave device used to adjust the RPMs comprises the command - whether it is a new fix point or a certain increase or decrease in the value of the stream. If the interpretation of the command by the slave device is to change the value, it is of course necessary to know the current RPMs relative to which differential value is being changed. The calculation of frictional losses in the annular space between the rod string and the production pipeline during the operating conditions, involves several parameters including Current_Calculation, Detention, Diameter of the Internal Pipe, External Diameter of the Rods, Fluid Density , Fluid Viscosity, Section Length, Depth of Pump Fixation. For r = 0.001, corresponding to the minimum value of the relative roughness of the pipe, and b, corresponding to External_Diameter / Internal_Diameter, that is the ratio between diameters, the correction factor of the diameters to calculate the Reynolds Number (Kb) is: ( 1-b4) 2 Kb = 1-b4 + (33) log (b) for which, the maximum value is 1. The Reynolds Number Correction Factor (Z) is calculated as: Z = (lb) 2 * (l-b2) / kb (1-b2) Z = (lb) 2 * + (34 ) Kb The Hydraulic Diameter is calculated as: | (Internal Diameter2-External Diameter2) | Hd = (35) (Internal Diameter + External Diameter) then the flowing area is obtained as follows: | (Internal Diameter2-External Diameter2) | 3.1416 * = (36) 4 factor Q = Rate__Current / Detention, and average speed in (m / s) Speed = Q (37) (350.62 * Flowing Area) where the Effective Reynolds Number Ref is determined by 406.86 * Veloied * Fluid Density * Hd / (Fluid Viscosity * z) (38) If Ref >; 2000, then the condition is Turbulent Flux f f = Factor_Colebrook (reef, rr); (Colebr'ook Factor) Therefore, Friction Losses can be established by (62.4 / 12) * ff * (3.281 * Speed) 2 * LENGTH_DE_SECTION / (2 * Hd * gravity); 62.4 Length_of_Section * (3,281 * Speed) 2 (39) 12 2 * Hd * severity if not, the condition is Laminar Flow and friction losses can be established by 8 * Viscosity + q + Length_of_Section (40) Internal Diameter 511.8505 * 10000 * Kb * 3.1416 * () 2 4 Once the friction losses are determined, the viscosity and density can be calculated. For the calculation of the Celerbrook_Factor, this calculation is based on a loop that has to be generated until the following condition is achieved: | df | < ftol Y | y | < ytol where, ytol = 0.0001 and ftol = 0.000001. As indicated by this invention df and y are calculated each time the loop is executed. It has been found that at most the Lasso is executed 20 times if this condition is not reached before. It will be noted that this procedure guarantees obtaining a convergence value for the Loop and the Colebrook Factor f. The Lasso calculations are as follows: Relative Asperity + 9.28 log () Number_Reynolds * Vf 1y = 2 * + (40) log (l?) Vf-1.14yp =; 2 * f1-5) 9.2Í9. 28 (Reynolds_number * f1-5 <? Spereza_Relative +) * log (10) - Reynolds_number * (f)) (41) then df = y / yp; and the new value for f is adjusted before repeating the loop f = fdf. If the loop is repeated more than 20 times, the loop is abandoned and the Colebrook Factor is the last value of f. As for the calculation of the viscosity, to determine it during the operating conditions, a loop is also generated to calculate an average value between two heights, that is, between two points of the production pipe string. For example, a head height of Well (0) and Depth of Fixation of the Pump, may be selected. According to the present invention, the Loop divides the pipe string into smaller pieces and then the Average Temperature is calculated in that piece. The average viscosity is then calculated under these conditions and the value is added to an accumulator at the end of the loop. It will be understood that when calculations have been made for the entire pipeline, theAccumulator is divided by the length of the string. This loop is mathematically equivalent to calculating the integral of the viscosity with respect to the height: Final Depth d Viscosity () * dh (42) Initial Depth dh Thus, in this case, the Initial_Degree corresponds to the point of the Wellhead and the Depth_final corresponds to the Depth of Fixation of the Pump, ent nn; double h, imudh, dh, tc, t, m, mu, muO, whdm = 0, rdm = 0, Initial_temperature; nn = 10; The height differential is the total length divided by 100 (100 pieces) dh = (Depth_Final-Depth_Initial) nn; where the Initial value for the viscosity differential is 0. imudh = 0; According to the present invention, the initial temperature is calculated with:Initial_Title = Temperature_of_Stay_head + (T_rperatura_Fondo_de_Pozo - T_tperatura_de_Cabeza_de_Pozo) (43)Depth_Initial * Depth_of_Perf sentence Fraction of Diluent In liquid r = Fraction_Diluente / (Fraction_Diluente-Fracción_Petróleo); Fraction of Water In liquidfagua = Fracción_Agua / (Fracción_Agua + Fracción_Diluente + Fracción _Petróleo); Calculation of the viscosity of the oil with the Visco 1 function with several parameters: vc = viscol (Oil_api, Temperature_of_Cobeza_of Well,Viscosidad_de_Cabeza_de_Pozo, Temp_de_Fondo, Viscosidad_de_Fondo_, Temp_Inicial): If the fraction diluente in the production pipeline (Bottom Injection of theDiluente) is not zero, so its viscosity is also calculated: vd = viscol (Diluente API Gravity, Bore_Standard_Texture, Viscosity_of_DiluentePozo, Temperature_of_Fondo,Viscosida'd_de_Fondo_de_Diluente, Temperature).
Auxiliary variable = er * < ? G (iog < vd_o.7 > > + < I-D * < iog (vc_c 7) >) (4 4.}.
And the viscosity of the mixture is determined from: vm = eVar? AbleAuxiliar-0. 7 (45) The density of the mixture is: Diluent Density = 0.000343 * (60-Temperature_current) + 141.5. (46) (13.5 + Diluent API) Oil Density = 0.000343 * (60-Temperature_current) + 141.5 (47)(131.5 + Petroleum API)dm = r * Density_Diluente + (1-r) * Oil Density • (48)In accordance, the Viscosity of the Mixture is obtained: Viscosity of the Mixture = vm * dm (49)Continuing with the calculation of the Average Speed, theInitial Viscosity of the Mixture is muO = Viscosity of the Blend Loop Calculate the Temperature .. as explained above to the depth H: TempC = Temperature_of_Stay_Heat + Temperature_of_Back-Temperature_of_Head_Hoot H * (50) Drilling Depth The Viscosity of the Mixture is again calculated to the TemC temperature corresponding to the viscosity at height H: mu = Viscosity of the Mixture According to the present invention, an average value is calculated between the two current viscosities, i.e. mu and muO, m = (mu + muO ) /2; and the difference between the two heights that is handled as Initial. The argument of the integral function is accumulated: imudh = (m * dh) + imudh; // integral of Mu * dh Then, the value of the initial viscosity is adjusted to calculate the next piece of the pipe string; mu0 = mu; End of the Loop It will be understood that the Loop is executed from the first point, that is, the Wellhead to the final point, that is, the Depth of Fixation of the Pump. Then the Integral is calculated: Viscosity = imudh / (Depth_Final-Depth_Initial) (51) The procedure in the Calculation of the Initial Viscosity referred to here as VISC01. VISCQ1: tkl = (Wellhead Temperature-32) / l .8 + 273.16 (52) tk2 = (Base Temperature-32) / l .8 + 273.16 (53) dl = 0.000343 * (60-Head Temperature of Well) + 141.5 /(131.5 + API) (54) d2 = 0.000343 * (60-Bottom Temperature) + 141.5 / (131.5 + API) (55) vl = Wellhead Viscosity / dl (56) v2 = Bottom Viscosity / d2 ( 57) a = (log (log (vl + 07)) -log (log (v2 + 0.7))) / log (tkl / tk2) (58) trk = tk2 (59) vr = v2 (60) tk = ( Current Temperature-32) / l .8 + 273.16 (61)The Current Temperature depends on the variable depth auxiiiar = e < ^ ° g (tk / trk) + 1 ° 5 (iog (vr + o.7),, (62) v = e (auxiliary variable) _0_7 (63)d = 0.000343 * (60-Temperature_current) + 141.5 / (131.5 + api) (64)Viscosity = (v) * (d) (65)It will be understood that this average viscosity is calculated assuming that there is a linear dependence between density and temperature. Of course, this procedure could be used instead of integrating it: the assumption would be that the diluent and the oil are completely miscible. If there is no diluted bottom injection, then the viscosity can be integrated through the VISCOl previously described here.
In accordance with the present invention, it has been found that the following procedure is useful for calculating the density of the fluid under well operation conditions. The various input parameters that are needed are: the last runoff, theoretical or practical, of the pump, the pressure at the point where the density is to be calculated, the temperature at the point where the density is to be calculated, the fraction diluent at the point where the density must be calculated (0 if not injected), qqg = volume of free gas above the pump (estimated by correlation), the specific gravity of the oil, the specific gravity of the diluent, the gravity specific to the gas, the specific gravity of the water, the water fraction, psep, tsep, rssep, the static background pressure, the gas-oil ratio, the bubble point pressure, the bottom temperature. Procedure: Calculation of the Oil Volumetric Factor: bov = Factor-Volumetri-Lib (Pressure, Temperature, Gravity-Specific-Gas, API-Oil, psep, tsep, rssep, Pressure-Bottom, Gas-Oil-Relationship, Pressure-Point -Burbujeo, Temperature-Bottom) (66) Calculation of the Volumetric Factor of the Gas: bgas = Factor-Volumetri-Gas (Pressure, Temperature, Gravity-Specific-Gas) (67) Quantity of Liquid: qql = (Fracción_Petróleo * bov + Fracción_Agua + Fraction_Diluente) / Fracción_Petróleo (68) Calculation of Detention (Holdup): detention = qql / (qql + qqg); no dripping in ideal situation (69) stop = Runoff + (1-Runoff) * stop: with runoff (70) Calculation of the RS factor for the gas:rsv = RS (Pressure, Temperature, psep, tsep, Specific_Gree_Gas, API_Petroleum, rssep, Bottom_Pressure, Oil_Gas_Relation, Pressure_Point_Burbujeo, Temperature_Fund) (71)Oil density rhoo = (62.4296 * Petroleum_Specific_Gevel + 0.076366 * rsv * Gas_Specific_Security_Gas) / (bov) calculated in lbs / ft3 (72) bl = l-Fraction_Pet 'Role + Oil_Fraction * bov; for Liquid Volumetric Factor (73) fw = Water_Fraction / bl; for water percentage (74) fd = Fraction_Diluent / bl; for percentage of diluent (75) fo = Fraction_Petroleum / bl; for percentage of oil (76) Density of all liquid: rhol = rhoo * fo + 62.4296 * (Specific Gravity_water * fw + Gravity_ Specific Diluent * fd (77) rhog = dengas (Pressure, Temperature, gravity, Specific_Gas) (78)The Density of the Mix can be calculated on the basis of these predecessor parameters: Density = rhol * stop + rhog * (1-stop) '(79) End The experts in the matter will notice that several procedures depend on the Procedure for the Calculation ofDensity 'described above here. Volumetric Factor: The various Parameters of Factor_Volumetri consist ofSpecific Gravity_Gas, API_Petroleum, psep (Pressure of theSeparator, if indicated, and Well head pressure, if it is not), tsep (Separator temperature if indicated andWell Head Temperature, if it is not), rssep (RS factor in the Separator, if indicated, and 0 if it is not),Pressure_Bank, Oil_Gas_Relation, Pressure_Point_Burbujeo,.
Temperature_Fund). double sgo, co, rsv, pbt, bov, sglOO; Calculation of the Factor for correlation of the volumetric factor: sglOO = Specific_Specific_Gas * (1 + 0.1595 * API_Petroleum) * tsep) * logl0 ((psep + 14.7) /114.7)); sgl OO = Specific_Garrage_Gas * (1 +). 1595 * API-Oil0- 4078) * psep + 14. 7 (tsep-0-2466) * logl0 114. 7 (80) Specific Gravity of the Oil: sgo = 141X / 131.5 + API_Petróleo) (81)Calculation of the RS Factor: rsv = rs (Pressure, Temperature, psep, tsep, Specific Gravity_Gas, API_Petróleo, rssep, Pressure_Fondo, Ratio_Gas_Petróleo, pb, tr) Calculation of the Bubbling point at temperature: pbt = fnpbt (Pressure_Point_Burbujeo, Temperature, Temperaturá_Fondo) (82) if the Pressure < = pbt use Glasso correlation, recommended by the University of Tulsa for APK20 Specific Gravity_Gas bov = rsv * () ° -525 + 0.9688 * Temperature _ sgo (83) bov = -6.58511 + 2.91329 * logl0 (bov) - 0.27683 * (loglO ( bov)) 2 (84) bov = l + 10 ov (85) otherwise Gravity_Specific_Gas bov = rsv * () ° -526 + or .9688 * Temperature sgo (86) bov = -6.58511 + 2.91329 * logl0 (bov) - 0.27683 * (loglO (bov)) 2 (87) bov = l + 10bov (88) co = logl0 (6. 8257) +. 5002 * logl0 (rsv) +0. 3613 * logl0 (API_Petróleo)+0. 7606 * logl0 (Temperature) (89) co = co-0. 35505 * logl0 (sglOO) (90) 1 0coco = / 1000/1000 (Pressure + 14.7) (91) bov = bov * eco * (pbt-pressure) (92)Calculation of the RS Factor: The various parameters include: (Pressure, Temperature, psep (equal to that previously explained), Pressure_Background, Gas_Gas_Relation, Bubbling Point Pressure, Bottom Temperature) Factor to Compensate the Gas Specific Gravity: sglOO = GRavedad_Específica_Gas * (1 + 0.1595 * API_Petroleum) * tsep) * logl0 ((psep + 14.7) /114.7)); sgl00 = Specific_Gravity_Gas * (1+) .1595 *] APIJPeleo0-4078) * psep + 14.7 (tse- ° -2466 ') * logl0 () 114.7 (93)rss = API_Petroleum / Temperature + 459.67) (94)Bubble Point Pressure Calculation at T temperature: pbt = fnpbt (Bubble Point Pressure, Temperature, Bottom Temperature) If the Bubble Point is Greater than the Static Bottom Pressure Yes (pbt > Bottom_Pressure) At most , the Pressure can be equal to the Bottom Pressure If API_Pet'roleo < = 30 rss = 0.5958 * sgl0007 72Mp + 14.7) 1-0014 * 1013-1405 * rss (95) if not rss = 0.0315 * sgl000.7587 * (p + 14.7) 1-0937 * 1011-289 * rss (96) yes (Pressure> Base_Pressure) (Pressure - Bottom_Pressure) rsly = | Re_lation_Gas_Petroleum + rssep-rss | * (pbt-Bottom Pressure) (97) if not rsly = 0 rss = rss + rsly (98) yes no If the Pressure < psep rss = rssep (99) yes no If the Pressure < pbt rss = rssep + Petroleum_Relation_Gas * (Pressure-psep) / (pbt-psep) (100) or rss = rssep + Relation_Petrol_Gas (101)Yes (rss &rssep + Petroleum_Relation_Gas) rss = rssep + Oil_Relation__Gas (102)It should be apparent to those skilled in the art that the final value for RS is rss, according to the disclosure of the present invention. Calculation of Bubble Point at Temperature T: The calculation of the bubble point involves the following parameters: Bubble Point Pressure at the Bottom Temperature (reservoir conditions), Temperature at which the Bubble Point Pressure is unknown, Bottom Temperature or Reservoir Temperature. For the scenario where the Bubble Point Pressure is unknown, the calculation proceeds as follows: (Background Temperature + 460) loglO (PregiónPointBurbujeo) * (Temperature + 460) (103) Returning to the Rules and procedures of the PLC, consider the Analysis 2 as corresponding to the well head pressure analysis, Events: Exceeded the Normal-High Limit: 1.15 * K6 cuental = cuental + l if the account > 3 Stop and Restart account Generate Alarm and Exit Loop if not Decrease RPMs (Decrease AOl) Wait for Recovery Time Bound Limit-Normal-Low: 0.85 * K6 count 2 = count2 + l If account 2 > 3 STOP and Reset Account Generate Alarm and Exit Loop if not Decrease RPMs (Decrease AOl) Wait for Loop Recovery Time Rule, 1 for fractured rod detection: Yes CALC <; K1 * CALC4 @ INPUT = 0 Stop and Generate alarm and exit Loop Procedure 1 to calculate the pump runoff: If it is not Stop Stop While CALC1 > 0.85 * CALC6 or Time_Transcurred < 30 seconds Continue with MATRIX [i] = CALC1 Store MATRIX [i] and Time StampAl [l] (time stamp) Loop Exit the Procedure Thus, the system stops at the request of this procedure (procedure 1). With reference to FIGURE 7, the axial load to be registered with its time stamp, in order to know what the load gradient vs. time. The brake system must be working to prevent the pump from losing the fluid column; during the first 30 seconds after the stop, the load and its time stamp are measured. As it is known, the Load is given by: Load = PUMP_AIR + (Fluid_Level * Fluid_Degree + Pressure_Cabez to_Pozo) + Weight_Varillas_En_Aire * BF @ 0RPM (104) substituting the fluid level (and the column related to the Well Head Pressure) for a Equivalent Fluid Column H: Load = PUMP_ AREA * (Fluid_Handle + Weight_Varillas_En_Aire * BF @ ORPM) (105)Differentiating now with respect to time: dCharge / dt = dH / dt * Gradient_Fluid * AREA PUMP (106) isolating dH / dt and multiplying by the area of the annular space (between the Production Pipe and the Rods: Handle): dH / dt * Asa = dCharge / dt * (Handle / Gradient_Fluid * AREA_BOMBA)) (107) the variation of Volume V displaced due to the variation of a column H is dV = Asa * dH and the rate associated with that volume is Q = dV / dt. Therefore: Qescurrimiento = dCarga / dt * (Asa / Gradiente Fluido * AREA_BOMBA) where dCarga / dt can be approximated to the average speed of the variation (in intervals) of the measurements taken by the PLC, upon request of this procedure. It will be understood that the runoff of the bona has to be determined under operating conditions. The operating conditions with respect to the pump, occur when the pump supports a value close to the Nominal Load. On the other hand, experimentally it is considered that the well is completely restored 30 seconds after the STOP. These are the two main reasons why the operational runoff of the pump is measured immediately after stopping, that is, this is the value closest to the Nominal Load for the pump in stop conditions, although within 30 seconds after the stop, we explain, the well has not yet been restored. This Operational Runoff of the pump can be compared with an operational run determined theoretically (through the characteristics of the pump), being able to detect prematurely a WEAR condition of the pump. Rule 2 for current detection: Exceeded the Normal-High Limit: K18 * 1.30 Stop and Generate Alarm and Exit the Loop Boundary Loop - Normal-Low: K18X.7 Stop and Generate Alarm and Exit Loop Loop For illustrative purposes, a general installation, step by step, of a system of the progressive cavity pump contemplated by the present invention is indicated below. In step 1, the stator is attached to the first joint of the production pipe string. Then the operator sequentially installs the following joints of the production pipeline until the stator is at the required installation depth. Subsequently the operator fixes the pipe in the well, using the conventional methods known in the industry. In step 2, the rotor is attached to the first rod of the string of suction rods for production. Then the rotor and the suction rod are inserted inside the production line. Then, the other sections of the suction rod are attached to the production rod string and the rotor is lowered to the stator depth, as will be understood by those skilled in the art, the rotor will pass through the interior of the stator and rest then on top. In step 3, the team raises the string of suction rods for production, until the full expansion and contraction effect has been compensated. Then, the operator marks the string of suction rods indicating its position in comparison with the elevation of the surface pipe. Then the calculations are made to determine the stretch suffered by the suction rods in the well during the dynamic operation process of the pump. The well service team raises the suction rod string and the final element of the suction rods is adjusted in length, with short suction rod lengths, that is, with "pony" type to compensate the length expected from the extension of the suction rods and the distance related to the stator stop. The critical spacing of the rotor in the stator has now been achieved. In step 4, the head is attached to the production line and then fixed to the well as required. It will be understood that the installation of the pump optimization system disclosed by the present invention will vary to some extent for each individual application. The instrumentation of remote control of the system and the input / output devices as well as the respective processor, they can be housed in various containment peripherals such as metal or fiberglass boxes with NEMA classification. The process input devices, included in the preferred embodiment as described above, are three transducers of various ranges. In addition, the head contains an extensiometric meter. In general, each device will have a two-wire input signal, 4-20 Ma current. Those additional instrumentation elements that are required based on the restrictions of the site, or that the operator requires, may be provided and connected to the system. As experts in the field will notice, in the installation and selection of the shielded cables to be used, the national and regional cabling codes must be adopted. The input signals of the process will be better organized when a single multiconductor cable serves as a bridge between the remote control terminal unit and the process system (with an RTU, PLC, etc.) at the well site. It will also be noted that the installation point of the transducers will vary from application to application. At the really minimal pressure, the transducers should be installed, preferably, vertically and perpendicularly to the line of the process being monitored. As stated above. The transducer's main cables must comply with local and national codes, and generally meet the customer's needs for a particular application. For what is disclosed in these reports to be useful, it is obviously necessary that the connections of the computer system are correctly installed, including the ACU unit and the motor controller. The RTU / PLC unit must be directly connected to the ACU unit, preferably through serial wiring that includes local cables, line extensions and switches, or using a conventional radio telemetry system. System designs can be used for group (multiple) and individual applications, and of course, they vary significantly. Preferably, the field connections between the RTU / PLC and the motor speed control must be made by analog or serial control wiring conventions. The field tests of the present invention have enabled optimization of the pump to the point previously unknown in the industry. FIGURES 8-11 show the results of one of said real field tests. The values illustrated represent the true answers and are not adjusted or mathematically embellished: the values illustrated represent the indicated relationships. The axial loads of the bearing reflect variations with respect to the nominal load of the bearing, in the static conditions of the well. Fluid levels represent variations in feet above the suction of the pump, compared to static fluid levels. Static conditions occur when the pump is turned off and the oil or gas is allowed to reach a stage of stagnation or equilibrium. The test responses offered very good representative values for the relationship between the axial load of the bearings and the fluid level.
Referring specifically to FIGURE 8, there is illustrated an RPM plot of the pump vs. The measured axial load of the bearings, as the RPMs are increased. Hence the relation between the measured axial loads of the bearings - corresponding to the thrust from the suction rod and to the hydraulic loads of the pump - and the speed of the pump. As it is known in the industrial, the pump RPM has a direct relation with the fluid production thereof. As the RPM increases, the pump flow increases proportionally. This plot suggests an increase in an axial load of bearings, as the flow rate / RPMs of the pump increases, which proves the existence of a mechanical relationship with respect to the increasing hydraulic load due to the flow rates of the pump. • Referring now to FIGURE 9, the relationship between the pressure relief of the pump on the surface and the pump RPM, or flow rates is illustrated. The increase in the pressure of the illustrated surface is the result of the back pressure of the flow line. It will be understood that the increased back pressure is mechanically related to a hydraulic load generated in the pump. These results support, therefore, the requirement of compensation for this relationship, in the prescribed calculation to establish fluid levels. FIGURE 10 shows the relationship between pump RPM / flow rate and fluid level. As the flow rate of the pump increases, the fluid level drops, obviously demonstrating the response of the well to the increased discharge of the pump. Therefore, this plot proves the premise that by increasing or decreasing the Pump RPM, the fluid level can be controlled. Referring now to FIGURE 11, the relationship between the thrust load of the axial bearings and the fluid level is seen therein. The value corresponding to the fluid level is indicated by a data line of the fluid levels that have been measured obtained from sonic measurements of fluid level - in the well. Also shown in said figure are the calculated values generated from the preferred embodiment, as previously described in detail. Thus, the illustrated relationship verifies the mechanical relationship between the fluid level and the axial load of the bearings. The calculated fluid level has been generated from the axial load of the bearings, using the formula explained in the present invention. It should be evident that the calculated value, verifies the accuracy and viability of the present invention to optimize the behavior of the pump as contemplated in the present invention. Prior to this invention, the ability to use these values derived from historical axial load measurements to evaluate, analyze, control and predict well behavior was not known in this field. The improved performance, obtained by the present invention as previously described here in detail, is illustrated in FIGURE 12. The behavior is shown both in the form of a plot of the rate of production against the feet of height of water and, alternatively, horsepower against tall feet. The data shown is based on water at 100 ° F. The relationship between the behavior and the dynamic level of the fluid, which reveals the present invention, is obvious. From the consideration of the specific embodiment and illustrative examples previously described herein, it is clear that other variations and modifications will become apparent. Accordingly, it should be clearly understood that the intention is not to limit the present invention to that which is particularly disclosed, or to the embodiment and examples that were previously described and illustrated in the accompanying drawings, but that the concept of this invention should be measured by the scope of the claims that are attached to this document.