MXPA98008394A - Controller to stop the pumping, using elephant of corio - Google Patents

Abstract

The present invention relates to operation of a control system (20, 200) of the pumping unit of an oil well, it is governed by a computerized automated control unit (88) that receives the measurements of the flow velocity of a Coriolis flow meter (28). The control unit causes the production of a rocker type pumping unit (22) to cease when measurements from the Coriolis flow meter indicate a decline in pump efficiency. The decline in pump efficiency indicates that a production fluid level (136) in the production line (108) has dropped below the uppermost set point for the pump piston (122). The production from the well is, consequently, stopped or closed to give the field enough time to accumulate the pressure and the corresponding fluid level that is required to restart the production operations.

Description

CONTROLLER TO STOP THE PUMPING, USING THE EFFECT OF CORIOLIS 1. Field of the Invention The present invention relates to the field of control systems for pumping units that extract production fluids from oil wells of rock formations below the surface of the earth. More specifically, the control system is a controller for stopping the pumping, for a pumping unit by rocker, which ceases production when the production fluids in the drilling well are disadvantageously low. 2. Foundation of the Problem Oil is produced from boreholes that reach a depth below the surface of the earth sufficient to drain production fluids that are naturally present in deposits or structural traps in rock formations. The deposits characteristically have a porosity (empty spaces within the rock) Ref.028517 and a permeability (a capacity for fluids to flow). The pressure in the reservoir in a specific well is known in the art as the pressure of the bottom point. The virgin deposits typically have a pressure from the initial bottom point that varies from approximately 19 to 24 pascals (0.4 to 0.5 psi) per 0.3 meters (1 foot) in depth; however, it is known that variations occur outside this range. The bottom point pressure decreases continuously during the life of a producing well because the production fluids are constantly being removed from the tank. Production fluids typically contain oil, water, and natural gas. Pressures at the bottom of the production well are difficult to predict and control because of the large number of variables involved. A very general explanation of the pressure reduction is that the pressure of the bottom point of a well differs from an average pressure in the reservoir according to a mathematical flow relation known as Darcy's law, the reservoir geometry, the considerations of the balance of the material, the properties of the production fluid (for example, compressibility and viscosity), and the properties of the rocks (for example, compressibility, porosity and permeability). A nonlinear pressure gradient exists along a radius taken from the borehole to the reservoir. The pressure gradient increases with the production speed of the well. The proximity to other wells and the geological characteristics that define the borehole limits also increase the rate of pressure reduction for a particular well. The depletion of the pressure of an oil field is often a significant problem that must be carefully managed to optimize the economic performance of an oil field. A problem arises when the available pressure of the bottom point is reduced below a value that is required to overcome the hydrostatic head in the borehole. For example, a well that is 2438 meters (eight thousand feet) deep can have a bottom point pressure of 144 kilopascals (3000 psi). Where the production fluids that originate from the well have a density that gives a combined pressure gradient of 63 pascals per meter (0.4 psi per foot of depth), a bottom point pressure of 153 kilopascals (3200 psi) calculated as the gradient equivalent to depth) it could be required to bring production fluids to the surface. On the other hand, the available reservoir energy or pressure is only capable of extracting the fluids at 2286 meters (7500 feet). The well can not produce a flow that occurs naturally, and must be abandoned unless an artificial lifting device can be installed to bring production fluids to the surface. Artificial lifting or lifting devices are installed to rejuvenate downward production speeds, and allows the additional recovery of large quantities of oil reserves from partially depleted reservoirs. Pumping units of the rocker type are the most commonly used type of extraction device or artificial lift. In rocker type pumping units, a rocker arm is connected to a drive mechanism, a fulcrum or fulcrum, and a counterweight system, as well as a subsurface rod and plunger assembly that reaches the production reservoir. The piston and rod assembly fits within a chain of production tubes that is used to transport production fluids to the surface. The oscillation of the rocker at the fulcrum causes the piston and subsurface rod assembly to move up and down over a path that typically varies up to about 2.4 meters (eight feet) or more. Near the bottom of the borehole, a valve system in the plunger closes during the upward stroke to raise a column of fluid to the surface. The valve system opens during the downward stroke to allow additional fluid to enter the column of the tube chain for the lifting or removal of the fluid, and again closes during the subsequent upward travel to seal the fluid from the fluid. Production in the tube chain during lifting or extraction. Valves cooperating to perform these opening and sealing functions are known in the art, respectively, as a fixed valve, a mobile valve, and a check valve. A problem that is known as "stopping the pumping" often occurs when the rocker type pumping units are installed in the substantially depleted reservoirs. Deposits with an exhausted pressure and those with very low permeabilities are often unable to supply production fluids at a rate that is sufficient to meet or exceed the rate at which a rocker-type pumping unit extracts production fluids from the well of sounding. Accordingly, the volume of the fluid in the borehole gradually declines until the plunger during its upward travel rises until the level of fluid that the reservoir is capable of supplying to the borehole has been passed. In this state, the well is said to be at least partially "stopped in the pumping" because the plunger is only able to fill by itself in its passage during the downward travel through a fluid column . The plunger for stopping the pumping during its downward travel can not be filled by itself until it passes below the fluid level of the borehole. As a result, the energy is wasted reciprocatingly moving a column of liquid with a reduced rate of fluid recovery, ie, the lift efficiency of the pump decreases as a consequence of stopping the pump. The piston during its descending travel also hits the fluid with a fluid hitting effect or water hammer that runs up the assembly of the rod and up to the rocker type, surface pumping unit. The striking effect becomes progressively worse when the fluid level continues to decrease because the piston speed increases at the point of impact. If repeated over a prolonged period, the striking effect induces fatigue with the corresponding failure of the system components. The links or threaded joints between the piston rods in the piston and rod assembly are especially vulnerable to fatigue failure induced by stopping the pump. The detection of a pumping stop condition is difficult because the plunger and rod assemblies reach descendingly large distances, for example, 1524 to 2743 meters (five to nine thousand feet). At these distances a significant elastic stretch occurs in the pump rod chain due to the modulus of elasticity of the materials that make up the pump rods. The speed of reciprocal surface movement, accordingly, must be synchronized to give the pump rods an opportunity to provide an optimum reciprocating path when the rods are stretched over long distances. In practice, this synchronization procedure is finely tuned by trial and error by experienced field personnel. The piston rods also make contact with the sides of the production line chain. Thus, a condition of pumping stop is not always detected only by surface vibrations.

The problems that arise from a pumping stop condition are solved by stopping the pumping during a temporary cessation of production from the well, that is, according to the industrial terminology, the well is "closed" or "remains inactive". Closure of the well accumulates the pressure of the bottom point when fluids flow into the reservoir to substantially reduce the pressure gradient between the average reservoir pressure and the downhole point pressure. The production starts ideally in a time interval after the increased pressure of the bottom point raises the fluid level in the well to a level above the uppermost set point for the assembly of the plunger. The well is closed again after a while to prevent the establishment of a pumping stop condition. Significant differences in production speeds can be obtained by changing the parameters of the closing cycle and the production cycle, that is, by varying the speed at which the pump rocker reciprocates, varying the time interval that the pump is operating, and varying the closing time or inactivity. A traditional method of identifying a pumping stop condition is to place a strain gauge on a portion of the pumping unit that is known as the drill beam. Alternatively, a load cell is placed on a portion of the rod assembly of the pump known as the polished rod, i.e., the rod of the uppermost pump. The measurements are plotted on cards showing the load of the polished rod on the vertical axis and the position of the polished rod on the horizontal axis. These cards are known in the art as dynamometer cards. Figure 1 shows a conventional dynamometric card of this type. There are variations of Figure 1 in which the data is plotted as a system of dimensionless numbers. The curve of Figure 1 has a well-developed substantially rhomboidal shape with a good separation between its upper and lower limits showing that the pump is operating very well. Figure 2 shows a second dynamometer card showing the effects of fluid beating due to the establishment of a pumping stop condition in the borehole. The upper and lower curves are no longer well separated. The lower curve has an angular curvature of 90 ° to 70% of the descending path, indicating the striking of the fluid.

Many problems are associated with the use of dynamometers to detect the impact of the fluid. Several variables affect the load of the polished rod or drill rocker, and their effects can be nullified or added together. The effects can also be shifted in a synchronized manner due to the stretching of the pump's rod assembly. Therefore, the dynamometer readings can sometimes not be interpreted to identify when the pumping stop has occurred. Additionally, voltage meters, load cells, and the electronic systems that support them sometimes fail to make the dynamometer system useless. An attempt has been made to detect the pumping stop problem through the use of volumetric measurements. An extremely complicated apparatus is required, and in the present the synchronized volumetric measurements are not commonly used to control the pumping stop in real production situations. Rhoads, U.S. Patent No. 4,854,164, shows a double tank structure where the double tanks are connected by dividing lines. The flow between the tanks is governed by pneumatically operated, electronically controlled valves. The electronic level indicators or the float switches or switches provide signals that represent the volume in the tanks. An electronic controller uses the valves to fill the respective tanks one at a time. The tanks each accumulate the production volumes of the multiple runs of a pumping unit. The electronic controller receives the signals from the level indicator inside a tank when the tank is filled, and causes the electronically controlled, pneumatically controlled valves in the split lines to switch the input fluid supply between the respective tanks to purge the filled tank at an appropriate time. A conduit connects the two tanks to allow the passage of production gas between the two tanks, but the reason for this exchange is unclear. Electro-pneumatic valves and level indicators are subject to failure, and the electronic controller is instructed to open all valves if a fault occurs, so that the well can continue production. Even so, this remedial action may not be possible when the valves have failed. The U.S. patent No. 4,859,151 discloses a pumping stop control mechanism having a spring-loaded flow indicator. A connection or link connects the spring-loaded flow indicator with a scale. An indicator needle on the scale identifies a minimum flow volume. The control mechanism closes the well if the spring-loaded flow indicator does not satisfy the minimum flow volume identified by the indicator needle. There remains a real need for a reliable volumetric method and apparatus to control a rocker type pumping unit, to avoid the establishment of a pumping stop condition in the production oil wells.

SOLUTION The present invention overcomes the problems identified above by providing a method and apparatus for controlling a rocker type pumping unit by the use of a Coriolis effect flow meter to avoid establishing a pumping condition in an oil well. production. The flow meter with Coriolis effect is particularly well suited for the task because it has an exceptional sensitivity to the flow rate, which is used to detect a reduction in the efficiency of travel of the corresponding volumetric pump to a pumping stop condition in a borehole. The present invention involves a pump control system for use in preventing the actuation of a rocker type pump unit while the fluid levels in a borehole are disadvantageously low. The control system includes a flow meter (preferably a flow meter with Coriolis effect) to measure a production fluid volume, produced by each upward travel of a rocker type pumping unit, or by averaging these volumes during over time. The meter provides production signals that represent the amount of production fluid that corresponds to the volumes produced by the pumping unit, and transmits these production signals to a central processing unit. The central processing unit receives the production signals and compares their corresponding representative production quantities against each other to identify a reduction in the volumetric pump travel efficiency induced by the establishment of a pumping stop condition in the borehole . The pumping stop condition occurs when an upper limit of the production fluids in the borehole has been reduced below a piston assembly attached to the rocker type pumping unit. In turn, the central processing unit transmits a signal indicating that the pumping stop condition exists. A system controller acts upon reception of this signal from the central processing unit to stop the surface production from the rocker type pumping unit and allows the accumulation of the bottom point pressure in the borehole. In the preferred embodiments, the control system stops production from the pumping unit by selecting one of two options. As a preferred option, the control system stops the drive of the pumping unit. In other circumstances, it is sometimes impractical to stop the drive of the pumping unit when the well is producing significant amounts of sediment in combination with the production fluids because the sediments tend to settle out of the production fluids and They deposit in places that cause damage to the pumping system. A costly reconditioning operation may be required to overcome the effects of sediments that settle out of the production fluids because the sediments may cause agglutination or scraping of the components of the pumping system at the bottom of the hole. In this last circumstance, the control system preferably continues the drive of the pump, but derives the surface production back to the borehole. Therefore, recirculation keeps suspended sediments in production fluids until fluids can be produced for commercialization. It is particularly preferred to use a flow meter with Coriolis effect to carry out the flow measurements. Flow meters with Coriolis effect can detect flow both forward and backward. The reverse flow indicates that certain valves, especially the check valve and the fixed or vertical valve, They have failed. Additionally, the volume (corrected for variations in temperature and pressure) that is produced by each stroke of the pump under normal operating conditions should equal the diameter of the surface area of the pump tube production tube chain. If the volume of fluid produced is less than this amount, the reduced volume indicates either a leak in the pipe or a leak in the mobile valve. The use of a flow meter with Coriolis effect allows these determinations to be programmed in the central processing unit. In contrast, a simple dynamometer pumping system, which requires very complex manipulations of the pump apparatus to achieve the same determinations that are readily available from the Coriolis data. Regular turbine meters and positive displacement meters will not work as well instead of Coriolis flow meters because displacement meters tend to clog (especially in the reverse flow) and lack of sensitivity and Reliability of flow meters with Coriolis effect. Some turbine meters also tend to plug during reverse flow, and this kind of meter is also very fragile and easily damaged under field operating conditions. Turbine meters are also based on an estimate of the density of the fluid that is supposed to be constant. This assumption produces an inherent error because the actual density of the fluid changes from a pump path to another pump path depending on the mixture of oil and water in the production fluid. Other features, objects and advantages will become apparent to those skilled in the art during a reading of the subsequent description in combination with the appended drawings.

BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 shows a dynamometer card representing a prior art method for verification of the operation of a rocker type pumping unit; Figure 2 shows a prior art dynamometric card showing the effects of fluid beating, which indicates that a pumping condition has been established in the borehole; Figure 3 shows a control system of the pumping unit including a flow meter with Coriolis effect and a computerized pumping control unit according to the present invention; Figure 4 shows a pump assembly for the bottom point at which a pumping stop condition has been established; Figure 5 shows a plurality of voltage signals supplied by the Coriolis flow meter of Figure 3 to the computer control unit of the pump, making it possible for the computer control unit to detect the pumping stop condition of Figure 4; Figure 6 shows an alternative method by which the computerized pump control unit of Figure 3 can detect the pumping stop condition of Figure 4; Figure 7 shows an alternative pump control system according to the present invention for use in wells producing highly sedimented production fluids; Figure 8 shows yet another pump control system according to the present invention for use in wells that produce fluids for central collection or collection stations with central measurement systems; and Figure 9 shows a schematic process flow diagram for controlling the operation of the pump control system according to the present invention.

DETAILED DESCRIPTION OF THE PREFERRED MODALITY SUPERFICIAL CHARACTERISTICS OF THE PUMP CONTROL SYSTEM Figure 3 shows a control system 20 of the pump according to the present invention. The control system 20 includes a conventional rocker-type pumping unit 22, a wellhead 24, through which a pumping unit 22 extracts the production fluids, a gas eliminator 26 for separating the gas produced from the production fluids, a flow meter with Coriolis effect 28, and an automated control center 30 that governs the operations of the control system 20 in response to the measurements carried out by the flow meter with Coriolis effect 28. The pumping unit 22 of the rocker type, is a conventional pumping unit, and is schematically shown to represent any type of reciprocating surface pumping unit. In the language of industry, the main components of the pump unit 22 include a rocker 32 connecting a rocker head 34 and a fulcrum 36 of the rocker arm. A pair of Pitman arms 38 connect the fulcrum 36 of the rocker with a counterweight or balance crank 40. An A-shaped frame structure 46 known as a Samson post supports the rocker 32 on the center pivot 48. A mounting and carrying bar 50 of steel cable engages the head 34 of the rocker arm with a polished rod 52. A magnet 54 is mounted on the crank 40, and the sensor 56 is used to detect or count the rotation of the magnet 54 An accelerometer 58 is used to detect low frequency vibrations in the Samson post 46. In operation, the crank 40 rotates to cause a corresponding rotation of the Pitman arms 38. The rotation of the Pitman arms 38 moves in reciprocating shape rocker 32 up and down using center pivot 48 as a fulcrum. The movement imparted to the rocker 32 in the rocker support 36 is reflected by the corresponding opposite movement through the rocker 32 in the rocker head 34. At the same time, the head 34 of the rocker arm imparts a vertical reciprocating movement to the polished rod 52 by means of the assembly 50 of the steel cable hanging and carrying bar. The head 24 of the well is a conventional wellhead that includes a sleeve or bushing 60 that receives materials for packing against the polished rod 52, to eliminate leakage between the polished rod 52 and the sleeve or bushing 60. The sleeve or bushing 60 is positioned above the flow diverter 62 leading to the gas eliminator 26. The head 24 of the well is connected by means of bolts to a production line and to a cover or wrapper hanger 64 which is used to hang very tight chains. lengths of tubular articles inserted into the borehole (not shown in Figure 3). The gas eliminator 26 includes a vertical cylinder 66 with screens having interior flow spaces connecting the flow diverter 62 with the liquid flow line 68 of the meter and the closed gas system 70 above. The outlet line of the liquid meter and the closed system of the upper gas 70 join to form a T 74 at an elevation above the flow meter with Coriolis effect 28. The production line 76 carries the production fluids from the T 74 to a production fluid separator system (not shown) in the direction of the arrow 78. The check valve 79 ensures that the flow through the production line 76 occurs only in the direction of the arrow 78. Accordingly , the gas is separated from the production fluids flowing through the diverter line 62 by the action of the vertical cylinder with screens 66. The liquids travel to the Coriolis flow meter 28 through the liquid flow line of the meter , and the gas bypass meter 28 through a closed upper gas system 70. The Coriolis effect flow meter 28 is installed between the liquid inlet line 68 of the meter and the liquid outlet line 72. The Coriolis effect flow meter 28 is preferably a commercially available Coriolis effect flow meter, such as the ELITE device Model CMF100M329NU and Model CMF100H531UN which are available from Micro Motion of Boulder, Colorado. These flow meters are also capable of operating as densitometers. Accordingly, a volumetric flow velocity can be calculated by dividing the total mass flow rate by the total density measurement. The Coriolis effect flow meter 28 uses electrical signals to communicate with the Coriolis transmitter 80 on the line 82. In turn, the transmitter 80 uses electrical signals to communicate with the automated control center 30 on the line 84. The preferred form of the transmitter 80 is the ELITE device Model RFT9739, which is available from Micro Motion of Boulder, Colorado. The meter 28 continuously measures the flow amount of the liquids through the liquid flow line 68 of the meter, and transmits the signals representing the flow quantities to the automated control center 30 through the transmitter 80. The center of Automated control 30 includes a high voltage power supply 86 and an operations control unit 88, which includes a central processing unit together with the program memory and controllers to electronically control the operation of the remote systems. The control unit 88 is preferably Model ROC306 from Fisher Industries of Marshalltown, Io a. The central processing unit and the program memory of the control unit 88 is programmed to facilitate the implementation of the control instructions through the control unit 88, which transmits the signals of the production data to a control system. collection of central field data (not shown) on line 90. High voltage power supply 86 receives the energy above line 91 of the power source, and distributes this energy when necessary to the components of system 20, for example, to the transmitter with Coriolis effect 80 on line 92.

Detailed Description of the Condition of Stop of pumping that is going to be Avoided Figure 4 shows a bottomhole assembly 100 that is connected to the control system 20. A borehole 102 has been drilled through thousands of meters or feet of geological strata that form a portion of the earth's crust . One of these strata includes a producing reservoir 104 that has a porosity that is filled with production fluids including oil, water, and gas. The metal liner 106 is made of a plurality of threadedly coupled tubes, inserted into the borehole 102. The liner 106 is raised to the surface, and hangs in tension from the hanger 64 of the liner and the pipe. (see Figure 3). The space between the liner 106 and the borehole 102 is filled with the cement 110 to prevent production fluids from being channeled under the liner 106 and to isolate the reservoir 104. The production line 108 hangs freely within the liner 106 of the pipe and liner hanger 64. Explosive shaped charges have been used to explode a plurality of perforations, eg, perforations 112 and 114, through liner 106 and cement 110 to allow production fluids from the reservoir 104 flow into the liner 106. A packer 118 seals the production fluids 116 within the liner 106 below the perforations 112 and 114. A plurality of cylindrical, elongated, threadedly interconnected elements form a chain of rods of drive 120 connecting the polished rod 52 (see Figure 3) with the plunger 122. The hollow cylindrical plunger 122 is circumscribed by a plurality of d and elastomeric seals, for example, seal 124, which compressively couples the internal diameter of production line 108 with sufficient force to raise a column 126 of production fluids within production line 108. Lower portion of plunger 122 it includes a ball and seat valve assembly 128 (ie, the mobile valve) which is sealed under the weight of the production fluid column 126. The perforations 130 in the upper portion of the plunger 122 allow the flow of the fluids of production between the hollow interior of the plunger 122 and the fluid column 126. The lower portion of the production line 108 includes a ball and seat valve assembly 132 (ie, the fixed valve) which is sealed under the compressive forces created by the downward stroke of the plunger 122, and opens to allow the entry of the production fluids 116 into the production pipe 108 under the relative vacuum created by the upper stroke of the plunger 122. As shown in Figure 4, a pumping stop condition has been established within the mount 100 of the bottom point. An average pressure P exists within reservoir 104. The flow of production fluids within liner 106 has created a gradient of pressure reduction along the arrow 134 in reservoir portion 104 surrounding probing well 102 such that the volume of the production fluids flowing to the liner 106 through the perforations 112 and 114 is insufficient to satisfy the rate at which the reciprocating movement of the plunger 122 is removing the fluids from inside the liner 106. Therefore, the production fluids 116 have an upper fluid level 136. The plunger 122 reciprocates in the direction of the arrow 138 by the action of the rocker head 34 (see Figure 3) on the polished rod. 52 through the chain of drive rods 120. The plunger 122 is shown at the full extent of its travel upwards. The upward stroke of the plunger 122 has exerted a relative vacuum on the production fluids 116 to open the ball and seat valve assembly 132 for the transfer of the production fluids 116 to the production pipe 108. The vacuum exerted by the plunger 122 on production fluids 116 has caused production fluids to release or distil the gas instantly, which creates a gas filled space 139 between the plunger 122 and the fluid level 136. The gas is also introduced into the production line 108 to form a gas filled space 139 when the upward stroke of the plunger 122 causes the uppermost fluid level 136 drops below the ball and seat valve assembly 132. The plunger 122 is beginning to descend towards the production fluids 116 at the fluid level 136 through the gas filled space 139. The valve assembly The ball and seat 128 is sealed under the weight of the fluid column 126 to prevent leakage of the production fluids in the column 126 into the gas-filled space 139. The plunger 122 travels down until the valve assembly The ball and seat 128 is slammed into the production fluids 116 at the fluid level 136 to create a striking effect of the fluid which is transferred to the pumping unit 22 (see Figure 3) through the ch drive rod 120. The ball and seat valve assembly 132 is sealed under the compressive forces created by the impact of the plunger 122 against the production fluids 116 at the level 136. The continuous downward path of the plunger 122 opens the assembly of ball valve and seat 128 through compressed fluid forces, against ball and seat valve assembly 132 to allow production fluids 116 to flow through the ball and seat valve assembly 128, through the hollow interior of the plunger 122, through the perforations 130, and towards the column of the production fluid 126. A subsequent upward stroke of the plunger 122 seals the ball and seat valve assembly 128 and opens the ball valve assembly and seat 132 for the repetition of the pumping cycle. The striking of the fluid of the plunger 122 against the production fluids 116 at the level of the fluid 136 is extremely undesirable for several reasons. During the course of time, a hitting effect of the repeated fluid of this type fatigued the drive rod chain 120 to cause a mechanical failure. This mechanical failure is very costly because the chain of broken driving rods must be removed from the borehole 102 and replaced. The consequences of the rupture of the chain of drive rods can be combined with each other with the effect that the well must be abandoned because repairs are no longer economically feasible. For example, the chain of depressed or crushed drive rods 120 may cause a corresponding failure in the production line 108, or the sediments may settle from the column of the production fluid 126 on the plunger 122 making it impossible to remove the chain of drive rods. crushed or sunk during repair operations. Additionally, the need for repair induces a shutdown of production during which no entry income is derived from the well. In addition, the operation of the pumping unit 22 (see Figure 3) becomes increasingly less efficient when the gas space 139 within the production pipe 108 is increased. The volume of production fluids 116 to be displaced with each stroke up the pump equals the surface area of the production line 108 taken through its internal diameter in a direction perpendicular to its elongation axis which it regulates the length of the upward stroke of the plunger 122. The presence of the gas-filled space 139, however, only allows the input of the production fluids 116 into the plunger 122 which starts at the level 136. When the gas filled space 139 It occupies approximately half the volume of the production fluids 116 that must be introduced to the plunger 122 during its downward travel, the efficiency of the volumetric pump fails to approximately half of its design performance. The energy costs remain constant because approximately the same amount of energy is required for the pump unit 22 to reciprocate the column of the production fluid 126 and the chain of drive rods 120 along the arrow 138. . Therefore, energy costs remain constant while the amount of production is reduced, and the amount of energy expended per unit production volume increases. In marginal wells, the resulting inefficiency and increased costs may require abandonment of the well for economic reasons if a corrective action is not taken.

Avoid the Condition of Pumping Stop The solution to the condition of the pumping stop shown in Figure 4 is to stop raising the production fluids 116 for a sufficient period of time to allow a reduction or elimination of the pressure reduction gradient within the reservoir 104 throughout. from arrow 134, that is, the well needs to be closed temporarily. When the production is resumed, the increased bottom point pressure in the borehole 102 is sufficient to raise the level 136 to a position above the uppermost waypoint for the plunger 122. Still, production must eventually be closed because the energy of the available reservoir is insufficient to satisfy the production speed demands of the plunger 122 at a given oscillation speed of the pump. Those skilled in the art are aware that the total production speed from the borehole 102 can be optimized by attempting to fine tune the operation of the pumping unit 22 by operating it at a speed that establishes a level 136 within the liner 106 which becomes very close to a stopped pumping stop condition without actually establishing the condition. The exact nature of the adjustments to the operating parameters of the pumping unit are usually determined by the person skilled in the field by adjusting the parameters including the reciprocating movement speed of the plunger 122, the duration of the closing time, and the duration of the pumping time. The operational and design considerations for the pumping units have been the subject of extensive literature, for example API Specification for Pumping Uni ts, 12 / a. Edition, API Specification IIE, API, Dallas (January 1982) (a publication of the American Petroleum Institute). In traditional practice, the optimal time of inactivity or closure is the minimum time of no net production that allows the pumping unit to produce during substantially equal intervals which are interspersed between each period of inactivity without stopping the pumping. By way of example, an operator can program the controller 88 to change the idle time between the pump intervals from thirty minutes to fifteen minutes. Following this program change, the well can produce 8,000 liters (fifty barrels) of oil and water in a first production interval before the pumping stops and must be closed again to allow the reservoir pressure to accumulate. A second pumping interval can produce 6400 liters (forty barrels) before the well has to be closed or inactivated, and a third interval can produce 4700 liters (thirty barrels). In this example, the consistent decline in production is an indicator that downtime needs to be increased, or the speed of reciprocating movement of the pump needs to slow down. In practice, these changes are made according to the analogies of nearby wells. In the event that there is no nearby well, the operator can make an initial estimate based on their experience, or the operator can follow the guidelines suggested by the API or other standard engineering calculations. Figure 5 shows a preferred method that the control unit 88 uses to verify or compare the production volumes which are raised to the surface by each reciprocating cycle of the plunger 122 for the purpose of determining when the pumping operations have established a pumping stop condition similar to that shown in Figure 4. The Coriolis effect flow meter 28 (see Figure 3) measures the mass flow rate and density of production fluids 116 (see Figure 4) which have been raised to the surface by the reciprocating action of the plunger 122. The flow meter with Coriolis effect 28 transmits the signals representing these mass flow rates and the densities with respect to the Coriolis transmitter 80 on the line 82. A turn, the Coriolis transmitter 80 processes the signals received from the Coriolis flow meter 28 to obtain a volumetric calculation by dividing the mass flow rate by the value of the corresponding density, and transmits the results of the calculations as voltage pulses to the unit control 88 on line 84. Figure 5 shows these voltage pulses for a plurality of successive pumping cycles 150, 151, and 152. Each pumping cycle includes an upward travel 153, 155, or 157 of the pump, corresponding to the plunger 122 (see Figure 4) and the corresponding downward path 154, 156, 158. Each upward path is associated with the largest production volume, which is represented by a plurality of uniform voltage pulses, for example, pulse 159, which cumulatively indicates the volume produced in each reciprocating pump cycle of the pump as indicated to the controller 88 by the magnet 54 and the detector 56 (see Figure 1). The Coriolis meter 28 and the transmitter 80 register the volumetric production even during the descending paths, such as the pulse 160 of the downward path 154, because the cylinder with screens ßß acts as an accumulator during upward travels (for example , the upward stroke 153) to retain an additional volume under high flow rate conditions that eventually pass through the Coriolis 28 meter under low flow conditions. For example, Figure 5 shows thirty-seven pulses counted in the upward travel 153 followed by three pulses during the downward travel 154 to provide a total of forty pulses in the reciprocating cycle 150. Similarly, the reciprocating cycle 151 counts twenty-nine impulses, and the reciprocating cycle 152 counts twenty-three. Each pulse represents a predetermined amount of volume, for example 0.8 liters (0.2 gallons). Accordingly, the controller 88 compares the sequential drop in efficiency against the volumetric flow corresponding to the initial upward run 153, that is, a fall of twenty-eight percent from cycle 150 to cycle 151, and forty-three percent from cycle 150 to cycle 152. Control unit 88 is programmed to cease operation of pumping unit 22 when pump efficiency falls below a level or threshold value. The operator selects this level, and enters it as a cut-off value that is stored by the controller 88. In Figure 5, the cut-off value is fifty percent efficiency. Thus, a decline of fifty percent or less in lift efficiency causes the control unit to close the borehole 102 by withdrawing power to the main mobile device 42. The control unit 88 has a timer, and again provides energy to the main mobile device 42 after an acceptable closing period. The duration of the closing time can be calculated by conventional mathematical algorithms stored as a program information in the control unit 88, or the operator can introduce a manual override in an attempt to optimize the production speed. Similarly, the control unit 88 accepts the reciprocating speed of the pumping unit 22 as a control input feature. Figure 6 shows another way in which the control unit 88 can compare or verify the averaged volumes of the production time that are raised to the surface by a plurality of reciprocating cycles of the plunger 122 for the purpose of determining when the pumping operations have established a pumping stop condition similar to that shown in Figure 4. A controller 88 receives voltage pulses similar to those shown in Figure 5, and averages the corresponding production volumes for a plurality of reciprocating cycles during the course weather. For example, a single point 161 on the curve 162 can be the production volume of the reciprocating cycles 150, 151, and 152 (see Figure 5) divided by three. Alternatively, the respective cyclic production volumes can be accumulated simply over time without being averaged. This time-averaging method advantageously avoids situations where the controller 80 can shut down or inactivate the well due to false readings that can result from aberrant production conditions, such as the expansion of a gas bubble in the production line 108 ( see Figure 4). Accordingly, the controller 80 does not compare the volume of the individual paths, but compares the average volumes or accumulated volumes over several reciprocating cycles, as detected by the magnet 54 and the sensor 56. The production periods 164, 166, 168 and 170 (that is, when the pumping unit 22 is reciprocatingly moving) are interspersed with periods when the well is closed or inactive for the accumulation of pressure 172, 174, and 176 (i.e., when the unit pumping 22 is not moving reciprocatingly). As in the production cycle 166, each production cycle starts at the highest average speed, and the controller 88 starts closing when the average production speed falls below a selected threshold value at the speed 180, for example, ninety. and five percent of the speed 178.

Alternative Modality for Use in Wells that Produce Highly Sedimented Fluids Figure 7 shows an alternative embodiment of the pump control system 20, especially the pump control system 200 for use in wells where it is undesirable to stop the reciprocating movement of the pump unit 22. An identical numbering has been retained for the characteristics of the system 200 in Figure 7 which are identical with respect to the characteristics of the pumping control system 20 in Figures 3 and 4. The main difference between the control system 20 and the control system 200 is the addition of the three-way valve 202 in the diverter line 62. The three-way valve 202 has two alternative configurations. In normal production operations, the three-way valve 202 receives the production fluids from the diverter line 62, and transfers all of the fluids thus received to the gas eliminator 26 through the tube 205. The second configuration of the three way valve 202 is for receiving the production fluids from the diverting line of the flow 62 and transfers all the fluids thus received through the return line 204 to the annulus between the liner 106 and the production line 108. Accordingly, all fluids produced from the borehole 102 are recycled so that there is no net production from the borehole 102. Alternatively, only a portion of the produced fluids can be recycled if the net production velocity from the bore still allows enough pressure to accumulate to overcome the problem of stopping the pump. The advantage in establishing continuous movement in the production fluids while no net production is obtained, is that the continuous movement keeps the sediments within the production fluids 116 in suspension without providing the sediments with a probability of settling . Without continuous movement, sand or other mineral particles could settle around the seals 124 of the plunger (see Fig. 4) within the pipe 108. In this position, the deposited mineral particles may need expensive repair by fixing plunger 122 in its place or by scratching or marking the seal 124 as well as the portion of the production pipe 108 next to the seal 124.

An Alternative Modality The Multiple Control System Oilfields are frequently located in isolated rural areas, and may have an area extension that covers tens of square miles. A piping system in the field is frequently installed to collect production fluids from a plurality of widely dispersed well sites. In the collection system, a chain of tubes connects a producer well to a manifold. Other wells are also connected to the manifold by other tube chains. The manifold is used to selectively combine the production of several wells, and supply the production to the previously sold processing facilities, such as a gas-oil separation plant. Therefore, the manifold is located in a centralized sales facility that is regularly maintained and visited by operations personnel. On the other hand, remote well sites receive less attention because the costs could be greatly increased if it were necessary to employ operating personnel at each well site. Regarding cost, it is better to conduct as many operations as possible to the center of centralized pre-sale processing, close to the multiple. Figure 8 shows a third embodiment of the present invention, that is, the control system 300, which partially closes a manifold valve to provide a pressure signal that begins closing a selected well. In Figure 8, an identical numbering has been retained for system components that are identical to the system components of the control system 20 of Figure 3. The control system 300 operates from a manifold 302, which includes a plurality of electronically controlled and pneumatically operated valves 304, 306, and 308. The control unit 88 governs the operations of the valves 304-308 through electrical signals transmitted on the line 310. In association with each of the valves 304-308, a chain of corresponding surface tubes 316, 318, or 320, connect the manifold 302 with a pumping unit 22 of the respective rocker type. Each tube string is provided with a corresponding pressure transmitter 322, 324, and 326. A signal transmission line, 328, 330, or 332, connects each pressure transmitter 322, 324, or 326, with a corresponding timing unit 334, 336, or 338. The manifold 302 preferably feeds a two-phase test separator 328 with the production fluids through the tubular line 330. The manifold 302 also feeds the main production separator 332 through the collection rail 334, which includes a plurality of tubular lines (for example, line 336) that corresponds to each valve on the manifold. The test separator 328 preferably includes a gas purge line 338 and a liquid drainage line 340. A flow meter with Coriolis effect 28 is mounted in the liquid drainage line 340 for the volumetric measurement of the fluids of liquid production including oil and water flowing through the liquid drain line 340. The gas purge line 338 and the liquid drain line 340 are combined on line 342 to feed the collection lane 334 which goes to the main production separator 332. The main production separator 332 is a conventional three-phase separator (gas, oil, and water), which supplies commercially available fluids to a sales and supply system 344. In the operation of the system 300, the control unit 88 configures the manifold 302 so that all the production fluids received from a single well correspond to a single valve (p or example, valve 306) to test separator 328 through line 330. The remaining flow currents from valves 304-308 that are not flowing to test separator 328, are either closed or configured to flow toward the valve. collection lane 334 in the separator of the main production. As in other embodiments, the Coriolis Effect Flow Meter 28 provides signals for measuring density and mass flow rate to the Coriolis transmitter 80 on line 350. The control unit 88 receives the volumetric signals from the transmitter of Coriolis 80 on line 352. Control unit 28 checks and compares these signals to identify an appropriate closing time for the well during the test, and proceeds to cut selected one of the respective pumping units 22 when required. The control system 300 differs from other embodiments in the manner in which the control unit 88 implements the closing of the respective pumping units. When the Coriolis measurements indicate that the well corresponding to the string of tubes 316 has established a stop condition of the pumping, the control unit 88 causes the valve 304 to partially close. The closing action of the valve 304 induces a rise or rise of a pressure in the tube chain 316. The pressure transmitter 322 detects this pressure rise, and transmits the measurement to the timer 334. The timer 334 is programmed to deny the power to the corresponding main mobile device 42 when the pressure at the transmitter 322 exceeds a maximum threshold value or a maximum pressure rise rate, for example 9.5 kilopascals (200 psi). Accordingly, the increased pressure caused by the restriction of the valve 304 operates as a signal that causes the timer 334 to close production. The timer 334 restores production by supplying power to the main mobile device 42 after a predetermined amount of accumulation time of the pressure at the bottom point. The control unit 88 stores the pumping time elapsed for the closing, like the control data of the program that will be used to operate the selected well when it is no longer under test.

Additional Advantages of the Use of a Coriolis Flow Meter System leaks sometimes cause problems in pumping operations. The use of a Coriolis flow meter advantageously facilitates the diagnosis of these problems. Specifically, a combined failure or leak in the surface check valve 79 (see Figure 3) and the ball and seat valve assembly 132 (the fixed valve) causes a counterflow of production fluids from the surface to the reservoir 104 under the force of gravity. The Coriolis flow meter 28 detects this backflow of production fluids, which typically occurs during the down stroke of the plunger 122 or during downtime. Accordingly, the control unit 88 is programmed to alert the operator at the time when there is a backflow. Other leaks can develop in the pipe or the ball and seat valve assembly 128 (the mobile valve). In these circumstances, the efficiency of the pump can not change from stroke to stroke (as indicated by a pump stop condition), but the efficiency of the pump is less than optimal. As indicated above, the volume of the production fluids supplied by an upper stroke of the pump must be equivalent to the cross-sectional area through the internal diameter of the production pipe 108 which regulates the length of the stroke on the upper stroke of the plunger 122 (see Figure 4). The supply of fluid quantities less than this volume indicates a leak in the production line 108 or the assembly of the ball and seat valve 128. Accordingly, the control unit 88 is programmed to alert the operator to a potential leak in the the moment in which a reduced efficiency of this type is deduced from the measurements provided by the Coriolis flow meter 28.

The Accelerometer In addition to the use of the pumping stop detection methods of FIGS. 5 and 6, the control unit 88 also receives information from the accelerometer 58 (see FIG. 3). The accelerometer 58 detects the low frequency vibrations that result from the beating of the fluid associated with the reciprocating movement of the pump unit 22 in a stop condition of the pump. Accordingly, the accelerometer data is available for use as a supporting indicator of the need to stop production in the event that pipe leaks or other mechanical problems prohibit the use of meter flow measurement information. of flow of Coriolis 28 in the identification of the existence of a stop condition of the pumping.

Characteristics of the Control Unit Program 80 Figure 9 schematically shows the control characteristics of the program of the control unit 88. These characteristics govern the operation of the control systems 20, 200 and 300. In step P400, the control unit 88 causes the pumping unit 22 (see Figure 3) begin to reciprocate the plunger 122. This reciprocating movement elevates the production fluids to the surface in the conventional manner in all reciprocating pumping units. The Coriolis flow meter 28 measures the production volumes that are associated with each cycle of travel detected by the magnetic sensor 56. The Coriolis transmitter 80 processes these measurement signals and then transmits them to the control unit 88. In the Step P402, the control unit 88 calculates the travel efficiency of the. volumetric pump indicated by the signals received from the Coriolis transmitter 80. This calculation is preferably carried out as a percentage differential calculation in the manner described above in association with Figure 5 or Figure 6. The percentage difference uses a volume of travel of the initial or maximum pump as the basis of the comparison. The initial volume can be selected as the first volume, but it is more preferably calculated as an average of the various cycles, for example, the first five cycles of travel. Alternatively, the initial value can be selected as a maximum value for each pumping session. This average technique or the selection of a maximum value is useful because systematic leaks in the production system may require the filling of the pumping system with the production fluids before a maximum pumping volume can be obtained. In step P404, the control unit 88 compares the travel efficiency of the most recent travel cycle (e.g., an upward travel and a downward travel or an average value of the last three upward travels and the last three travels down) against a threshold value that is preferably given to the control unit 88 as the input of the program data by the operator. If the efficiency has not fallen below the threshold value, the reciprocating movement of the pump continues, and step P402 calculates a new efficiency. A decline in the efficiency of the run indicates that a stop condition of the pump has been established in the well. Accordingly, when step P404 diagnoses this condition as an efficiency below the threshold value, the control unit 88 causes the pumping unit 22 to terminate the reciprocating movement in step P406, that is, the well is closed. In step P408, the Coriolis flow meter 28 continues to measure mass flow rates of production even when there is no positive flow of production fluids that originates from the reciprocating movement of the pump unit 22. The step P408 alerts the operator that there is a leak in the check valve and the valve is fixed if the Coriolis meter 28 detects a back flow of the production fluids during the closing period. In step P410, a timer in the control unit 88 (or a timer unit associated with the control unit 88) determines whether a period of time has elapsed to allow a buildup of sufficient pressure in the reservoir 104. The accumulation time it can be calculated according to a variety of conventional engineering methods, including exponential integral calculations, curve type analysis, procedures established by the American Petroleum Institute, or operator input data. If the timer indicates that the pressure build-up period is not sufficient, the Coriolis flow meter continues to check the backflow in step P408. When the accumulation period has elapsed, the control unit again causes the pumping unit 22 to reciprocate in step P400.

It is noted that in relation to this date, the best method known to the applicant to carry out the aforementioned invention, is that which is clear from the present description of the invention.

Having described the invention as above, property is claimed as contained in the following

Claims (20)

1. A pump control system for use in terminating the drive of a pumping unit while the fluid levels in a borehole are disadvantageously low, the system is characterized in that it comprises: means for measuring a volume of production fluid corresponding to the reciprocating movement of a reciprocating pumping unit, the measuring means include a Coriolis flow meter and means for calculating the volume of the production fluid by dividing a mass flow rate by a value of the density corresponding to the velocity of mass flow; means for producing electronic signals representative of a volume of the production fluid corresponding to each cycle of travel of a reciprocating pump unit; means operating in response to the reception of electronic signals from the means to produce electronic signals, to compare the volumes of the production fluid to identify a reduction in the efficiency of the lift along the pump path; means for generating a signal representative of the reduction in the efficiency of the pump path; and means operating in response to the generation of a signal representative of the reduction in the efficiency of the pump path to stop surface production from a pumping unit.

2. The system according to claim 1, characterized in that the stop means include means for delaying the actuation of a pumping unit for a period of time sufficient to allow the pressure from the bottom of the hole to accumulate in a borehole.

3. The system according to claim 1, characterized in that the stopping means include means for reintroducing the surface production to a borehole to prevent deposition of sediments on the components of the pumping system at the bottom of the bore.

4. The system according to claim 1, characterized in that the stop means include a manifold that provides means to increase the pressure on a well flow line.

5. The system according to claim 4, characterized in that the stopping means include means operating in response to the increased pressure to stop the actuation of a pumping unit.

6. The system according to claim 1, characterized in that it includes means for adjusting the operating parameters of the pump selected from a list consisting of pump strokes per unit time, closing time, and pumping time.

7. The system according to claim 1, characterized in that it includes means for detecting a problem selected from a group consisting of a leak in the check valve and a leak in the fixed valve.

8. The system according to claim 7, characterized in that the detection means include means for producing signals representative of a backflow of the fluids produced in a borehole.

9. The system according to claim 1, characterized in that it includes means for analyzing the electronic signals of the measuring means to identify a problem selected from a group consisting of a leak in the pipe and a leakage of the mobile valve.

10. The system according to claim 1, characterized in that the comparison means include means for calculating a difference between the successive electronic signals of the means for producing electronic signals.

11. A method for controlling a pumping unit to prevent the drive of the pumping unit while the fluid levels in a borehole are disadvantageously low, the method is characterized in that it comprises the steps of: measuring a volume of the production fluid, produced by a pumping unit through the use of a Coriolis flow meter, where the step of the measurement includes calculating a volumetric flow velocity by dividing a mass flow rate by a density value corresponding to the velocity of mass flow; producing electronic signals representative of the volume of production fluid corresponding to each upward travel of the pumping unit; comparing the electronic signals to each other to identify a reduction in the efficiency of the volumetric pump travel induced by an upper limit of the production fluids in the borehole that has fallen below a piston assembly attached to the pump unit; transmit a signal representative of the condition; and stopping the surface production of the pumping unit to allow the accumulation of pressure at the bottom of the hole in the borehole.

12. The method according to claim 11, characterized in that the stop step includes a step of retarding the actuation of the pumping unit for a period of time sufficient to allow the pressure at the bottom of the hole to accumulate in the borehole .

13. The method according to claim 11, characterized in that the stopping step includes a step of reintroducing the surface production to the borehole to prevent deposition of the sediment on the components of the pumping system at the bottom of the bore.

14. The method according to claim 11, characterized in that the stop step includes a step of using a manifold to increase the pressure on the well flow line.

15. The method according to claim 14, characterized in that the stop step includes a step of responding to the increased pressure by stopping the drive of the pumping unit.

16. The method according to claim 11, characterized in that it includes a step of adjusting the parameters of the pump operation selected from a list consisting of pump strokes per unit time, closing time, and pumping time.

17. The method according to claim 11, characterized in that it includes a step of detecting a problem selected from a group consisting of a leakage of the check valve and a leakage of the fixed valve.

18. The method according to claim 17, characterized in that the step of the detection includes a step of producing signals representative of a backflow of fluids produced in the borehole.

19. The method according to claim 11, characterized in that it comprises a step of analyzing the electronic signals to identify a problem selected from a group consisting of a pipe leakage and a leakage of the mobile valve.

20. The method according to claim 11, characterized in that the step of the comparison includes a step of calculating a difference between some successive signals.