RU2726697C2 - Methods and device for determination of well pumps production volume - Google Patents

Abstract

FIELD: drilling of wells.

SUBSTANCE: group of inventions relates to downhole pumps, and more specifically to methods and apparatus for determining volume of production of downhole pumps. Method involves measuring the first amount of fluid extracted from the well by the pump during the first pump stroke. Pump first dynamogram is calculated based on first stroke. First area of first pump dynamometer is determined. Ratio of proportionality of pump leakage is determined on the basis of the first amount of extracted liquid and the first area. Second pump dynamogram is calculated based on pump second stroke. Second area of the second pump dynamometer is determined. Second amount of fluid produced by pump during second stroke is determined based on coefficient of leakage proportionality and second area. Device includes a housing and a processor located in the housing, wherein the processor is designed to perform the above actions.

EFFECT: technical result is higher efficiency of well pump production volume determination.

20 cl, 12 dwg

Description

AREA OF TECHNOLOGY

[001] The present invention relates generally to downhole pumps, and more particularly to methods and apparatus for determining the production volume of downhole pumps.

LEVEL OF TECHNOLOGY

[002] Downhole pumps are used to pump fluid from a formation by moving a piston relative to a wellbore. A gap is provided between the piston and the wellbore so that the cuttings do not adversely affect the performance of the downhole pump. However, this clearance allows for leakage between the piston and the wellbore. In addition, in some cases, the pump may not fill completely during pumping. As a result, the fill rate of the pump affects the amount of fluid produced by the pump.

BRIEF DESCRIPTION OF THE GRAPHIC MATERIALS

[003] FIG. 1 illustrates a pumping unit comprising a typical device used to determine well productivity in accordance with the teachings of the present invention.

[004] FIG. 2 illustrates an exemplary surface dynamogram that can be obtained in accordance with the teachings of the present invention.

[005] FIG. 3 illustrates a typical pump dynamometer chart that may be obtained in accordance with the teachings of the present invention.

[006] FIG. 4 illustrates a typical pump dynamogram obtained using a pumping unit having an anchored tubing string.

[007] FIG. 5 illustrates a typical pump dynamogram obtained using a pumping unit having an open tubing string.

[008] FIG. 6 illustrates a typical pump dynamometer chart obtained with a pumping unit in which the pump is not primed during downstroke.

[009] FIG. 7 is a block diagram showing an exemplary method for determining a pump fill rate, the method may be implemented by the exemplary apparatus of FIG. 1.

[0010] FIG. 8 is a block diagram representing an exemplary method for calculating pump inlet pressure that may be implemented with the exemplary apparatus of FIG. 1.

[0011] FIG. 9 is a block diagram showing an exemplary method for controlling a pumping unit based on pump inlet pressure, which may be implemented by the exemplary apparatus of FIG. 1.

[0012] FIG. 10A and 10B are a block diagram representing an exemplary method for determining production of a pumping unit that may be implemented with the exemplary apparatus of FIG. 1.

[0013] FIG. 11 illustrates a processing platform for implementing any of the exemplary methods of FIG. 7, 8, 9, or 10A and 10B and / or the typical device of FIG. 1.

[0014] Specific embodiments of the invention are shown and described in detail in the foregoing drawings. In the embodiments described herein, like or identical reference numbers have been used to identify the same or similar elements. For clarity and / or brevity, the drawings are not necessarily drawn to scale, and specific features and specific views of the drawings may be shown enlarged or schematic. In addition, some embodiments of the invention are disclosed herein. Any features from any embodiment of the invention may be included, replaced, or otherwise combined with other features from other embodiments.

DETAILED DESCRIPTION OF THE INVENTION

[0015] An oilfield downhole reciprocating pump (eg, a sucker rod pump) is often considered a positive displacement pump because a plunger or piston with a known diameter moves a known (or calculated) distance during each stroke. It is preferable to use the pump as a measuring device for roughly estimating the daily production from the well, linking the number of pump strokes per day and the pump geometry with the expected production volume. In other words, since the pump displacement is known (or calculated), it is desirable to use the number of strokes over a period of time to estimate the volume of fluid produced. However, borehole oil pumps do not work as true positive displacement pumps because pumps are usually designed with significant clearance between the piston and the cylinder through which the piston reciprocates, resulting in leakage or sliding.

[0016] In accordance with the teachings of the present invention, information associated with downhole reciprocating pumps can be used to approximate production from a corresponding well. In general, production can be estimated based on pump area and pump stroke distance, which corresponds to the calculated displacement for each stroke. However, known production estimates do not take into account other factors that can affect the produced volume, such as, for example, pump fill and / or pump leakage. The exemplary methods and apparatus described herein can be used to more accurately estimate production based on at least these two variables.

[0017] Pump filling refers to the amount of fluid in the pump cylinder (eg, between the piston and the bottom of the cylinder). If the pump cylinder is not completely filled when the piston moves down during the downstroke, the volume of fluid pumped by the piston on the upstroke is different from the pump displacement. The methods and apparatus disclosed herein can be used to determine a pump fill rate (eg, degree), which is useful for a variety of rod pump control options. For example, the pump fill rate is a highly desirable process variable for controlling the speed of the sucker rod pump and / or controlling the on / off of the sucker rod pump. When adjusting the speed of a sucker rod pump, the pump speed can be decreased if the pump fill rate is below the target value (eg setpoint, threshold), and increased if the pump fill rate is higher than the target value. The pump fill rate can be monitored for on / off control, and when the pump fill rate falls below the target for a given number of strokes, the pump can be stopped and the well can be left idling to fill the well casing with production from the reservoir. Therefore, when pumping is resumed (at the end of the shutdown), sufficient fluid may be available to fill the pump. These strategies can be used to reduce energy consumption per unit of fluid produced and reduce wear on pumping system components, thereby extending the life of the pumping system.

[0018] In addition, borehole pumps are designed with a clearance or clearance between the piston and the cylinder or pipe, within which the piston reciprocates. Therefore, on the upstroke (for example, when there is a pressure difference across the piston), a leak occurs between the pump and the cylinder. As a result, the volume of the actual pumped fluid is less than the predicted or estimated volume. The exemplary methods and apparatus described herein can be used to determine the Leak Proportionality Factor, which can be used to more accurately predict the volume of oil produced in each stroke. In some examples, the pump fill rate or factor is also used to determine the proportional factor of the leak. Therefore, the generic methods and apparatus described in this document can be used to determine pump fill and leakage, which can then be used to more accurately estimate production. In particular, production from a well can be derived based on the number of pump strokes, the geometry of the downhole pump, a typical leakage proportional factor and / or pump fill factor. Stroke refers to a complete cycle of upstroke and downstroke.

[0019] In addition, in most reciprocating sucker rod pump applications, the operator or owner may want to operate the well at or near "fast pumping", which is the point at which the amount of available fluid in the wellbore is more or less suitable to prime the pump. ... In general, operating a well near fast pumping results in a low practical bottomhole pressure. In addition, as the downhole pressure decreases, the flow into the wellbore increases. Therefore, well operation at or near rapid pumping usually results in maximum well production. However, in some cases, the operator may want to operate the well at a given wellbore pressure that is different from the fast pumping pressure. This strategy can provide excellent reservoir control as it allows the lighter hydrocarbon components to remain in solution with the liquid phase as products flow to the wellbore. By keeping the product only in the liquid phase, the effective permeability to liquids is increased. In some cases, this approach results in higher overall hydrocarbon recovery (although in some cases recovery may take a longer period of time). To operate a well at (or near) a given pressure in the well (for example, setpoint, threshold), some method is needed to measure or estimate the pressure in the wellbore (at the pump inlet). Certain measuring instruments are available to directly measure these values. However, these instruments are usually expensive and difficult to install. The exemplary methods and apparatus described herein provide a method for determining a differential pressure across a pump using the pump fill factor described above. This allows the pump inlet pressure to be sensed and used to control the pump speed. The pump inlet pressure can be used to control the speed of the sucker rod pump and control the on / off of the sucker rod pump. In other words, depending on the pump inlet pressure, the pump speed can be decreased or increased and / or the pump can be stopped or started.

[0020] FIG. 1 illustrates a typical pumping unit 100 that can be used to recover oil from oil well 102. Pumping unit 100 includes a base 104, a rocker arm 106 and a rocker arm 108. In the illustrated example, pumping unit 100 includes a motor or motor 110 that drives belt transmission 112 for rotation of the gearbox 114 and, in turn, rotation of the crank arm 116 and counterweight 118. The connecting rod 120 is connected between the crank arm 116 and the balance bar 108, so that when the crank arm 116 rotates, the connecting rod 120 and the balance bar 108 move. Since the balance bar 108 pivots about the pivot point and / or support of the rocker arm 122, the rocker arm 108 moves the rocker arm of the sucker rod pump 124 to reciprocate the downhole pump 126 through the hanger 128, the polished rod 130, the tubing string 132, and the sucker rod string 134.

[0021] In the illustrated example, the reciprocating movement of the beam pump 124 moves the piston 136 of the pump 126 within the cylinder 138 (eg, wellbore, casing, casing, etc.) of the pump 126 to extract fluid from the surrounding formation 140 (indicated F). During the lift of piston 136, fluid is drawn into wellbore 138 through a stationary valve 142 (eg, a bottom valve) located at the bottom of a wellbore 138. Piston 136 contains a movable valve 144 (eg, a top valve) that is in a closed position. In fact, the piston 126 pushes the fluid in the tubing 132 located above the piston 136 to the surface. The downstroke opens movable valve 144 of piston 126, which allows fluid in cylinder 138 to flow through valve 144 into tubing 138 above piston 126. At this time, stationary valve 142 is closed. The piston 126 then moves upward on its subsequent upstroke to push fluid in the tubing 132 toward the surface, and so on.

[0022] To ensure that the cuttings will not adversely affect production and / or adversely affect the movement of the piston 136 relative to the wellbore 138, a gap and / or clearance is provided between the piston 136 and the wellbore 138. The clearance reduces the volume of fluid produced pump 126 during each stroke of pumping unit 100.

[0023] To accurately determine production from pump 126, pumping station 100 includes a generic device and / or controller for sucker rod pump 146. In this example, data from pumping station 100 and / or associated data is received by an input / output (I / O) device 148 of the rod pump controller 146, and are stored in memory 150 accessible to processor 152. As described in more detail herein, processor 152 may perform calculations to determine, for example, a typical pump fill rate (for example, based on the volume of fluid contained in the pump 126), pump 126 inlet pressure, typical leakage proportional factor (for example, in ² / lbf), the volume of fluid leaking through pump 126 (for example, in ³ ), and / or the total amount of fluid produced during the stroke of the pumping unit 100 and / or a predetermined period of time. In some examples, the components 148, 150, 152 of the device 146 are located within a housing 147, which may be located at the site of the pumping station 100. In other examples, the device 146 may be located in a remote location (eg, at a base station or control room).

[0024] Several methods have been proposed to calculate estimated production using a wellsite controller that can count pump strokes and measure the efficiency of individual strokes. However, the disadvantage of these prior art methods is the need to independently evaluate or measure the amount of leakage that occurs during each stroke. US Patent Application No. 13/187330, filed July 20, 2011, which is incorporated herein in its entirety by reference, sets out a method that applies a principle derived from laboratory pump tests and, in particular, shows that pump leakage is directly proportional to the pressure difference across the pump (eg, the difference between the pressure inside the cylinder 138 and the pressure above the piston 136). The pressure difference across the pump is directly proportional to the load or stress on the sucker rod string. A traditional diagnostic tool used with reciprocating rod pumps is called a dynamogram, which is a graph of load (eg force) versus position (eg linear displacement) for a single stroke of a pumping unit. Two types of dynamometer charts are commonly used. The first type of dynamometer chart is a surface dynamogram, which is obtained from the results of measurements performed on the surface, and displays the dependence of the load on the polished rod on the position of the polished rod. The second type of dynamometer chart is called the pump dynamogram and is calculated using the data collected for the surface dynamogram and a mathematical calculation process that simulates the flexibility of a sucker rod string.

[0025] FIG. 2 illustrates an exemplary dynamometer chart of surface 200 that can be generated in accordance with the teachings of the present invention using data associated with the vertical displacement of polished rod 130 versus time and data associated with voltage on polished rod 130 over time. In some examples, the dynamometer chart of surface 200 represents a case in which the downhole pump 126 is operating normally with an appropriate pumping fluid. As illustrated in FIG. 2, the X-axis 202 corresponds to the position of the polished rod 130 and the Y-axis 204 corresponds to the load on the polished rod 130.

[0026] In the example illustrated in FIG. 2, reference numeral 206 (at point 1) corresponds to the moment when the polished rod 130 begins its upward movement (eg, upward travel) to begin to raise the column of fluid. Between reference numbers 206 and 208 (at point 2), an increase in stress on the polished rod 130 is shown as the polished rod 130 is stretched and the column of fluid is raised. Reference number 208 corresponds to the moment when the pumping unit 100 carries the weight of the sucker rod string 134 and the weight of the accelerating column of fluid. Between reference numbers 208 and 210 (at point 3), as the upstroke continues, force waves arrive at the surface, causing the load on the polished rod 130 to fluctuate. Reference number 210 represents the point at which the polished rod 130 reaches its maximum upward displacement. Between 210 and 212 (at point 4), the fluid load is transferred from the sucker rod string 134 to the tubing string 132, which reduces the stress in the polished rod 130. The reference number 212 corresponds to the moment when the load is mainly and / or completely transferred to tubing 132. Between 212 and 206, as the downstroke continues, the force waves are reflected to the surface, causing an irregular load on the polished rod 130 until the polished rod 130 reaches the bottom and starts another stroke.

[0027] FIG. 3 illustrates a typical pump 300 dynamogram that can be generated in accordance with the teachings of the present invention using data associated with the position of the polished rod 130 and the load on the polished rod 130. In some examples, the dynamogram of the pump 300 is generated using data measured at the surface. As illustrated in FIG. 3, the X-axis 302 corresponds to the position of the downhole pump (eg, the position of the piston 136), and the Y-axis 304 corresponds to the load on the downhole pump. Points 1, 2, 3 and 4 from FIG. 2 are illustrated and in FIG. 3. Using the dynamometer chart of pump 300, the pressure difference across pump 126 is proportional to the height (eg, vertical length) of the dynamometer chart of pump 300. Therefore, the leakage through pump 126 is directly proportional to the height of the dynamometer chart of pump 300. Using the trapezium method (or other similar method), the measured data from the stroke of the pumping unit can be integrated to determine the area of the pump 300. The total area of the pump 300 is the amount of work performed (for example, the force acting when moving a certain distance). Thus, the dynamometer chart area of pump 300 represents the work performed by pump 126.

[0028] Under ideal conditions (eg, when pump 126 is full and there is no tubing movement and / or leakage), if the outlet pressure (eg, fluid pressure above piston 136) and pump 126 inlet pressure (eg, fluid pressure below the piston 136) are known or estimated, the area of the dynamometer chart 300 can be used to determine the ideal volume of produced fluid V _stroke using Equation 1 below.

Уравнение 1

Equation 1

[0029] In Equation 1, V _stroke is the ideal (eg, no leakage) volume of fluid produced during a stroke (eg, in ³ inches) [1 inch = 2.54 cm] A _PC is the area of the pump dynamogram (eg , in lbf * in) [1lbf = 4.45 N] for stroke, and ΔP is the pressure difference across piston 136 (for example, the difference between pump inlet pressure and pump outlet pressure) (for example, in lb -force / inch ² ). However, the relationship shown in Equation 1 can only be used for a complete pump dynamometer chart in a well that has an anchored tubing string. In particular, in some cases, tubing 132 is anchored or secured to prevent movement and / or stretching of tubing 132 during operation. If tubing 132 is not anchored, tubing 132 may move and / or stretch during operation. This can affect the pump 300's dynamometer chart area.

[0030] For example, in FIG. 4 illustrates a typical ideal “full” pump 400 dynamometer chart for a well (eg, well 102) with an anchored tubing string. The X-axis 402 corresponds to the position of the downhole pump and the Y-axis 404 corresponds to the load on the downhole pump. As illustrated in FIG. 4, the shape of the dynamometer chart 400 is substantially rectangular. Even with irregularities that may exist, the ideal area A _{PCI of a} pump dynamometer chart can be determined (e.g. approximated) using Equation 2 below.

Уравнение 2

Equation 2

[0031] In Equation 2, A _PCI is the ideal area of the pump dynamogram (for example, in * lbf), S _max is the maximum pump position (for example, in inches), S _min is the minimum pump position (for example, inches), F _max is the maximum pump load (e.g., lbf) and F _min is the minimum pump load (e.g., lbf), which are indicated in FIG. 4.

[0032] In some cases, as described above, the tubing is not anchored or secured. As a result, the tubing string can stretch during operation, thereby affecting the area of the pump dynamometer chart. FIG. 5 illustrates a typical ideal "full" pump 500 dynamometer chart for a well (eg, well 102) with open tubing. The X-axis 502 corresponds to the position of the downhole pump and the Y-axis 504 corresponds to the load on the downhole pump. As illustrated in FIG. 5, pump 500 has a parallelogram shape. In particular, the sides of the dynamometer chart of the pump 500 are not as steep as, for example, the sides of the dynamo chart of the pump 400. The slopes of the sides of the dynamo chart of the pump 500 reflect the stretching and retraction of the tubing string as the fluid load is transferred from the sucker rod string. 134 (for example, on an upstroke) to tubing 132 (for example, on a downstroke). The dF / ds pump dynamo side slopes can be determined using Equation 3 below.

Уравнение 3

Equation 3

[0033] In Equation 3, dF / ds is the slope of the sides of the pump dynamometer (eg, in lbf / in), E is the modulus of elasticity of the tubing material (eg, in lbf / in ² ), A _tubing is is the cross-sectional area of the tubing string (for example, in ² inches), and L is the length of the open tubing string (for example, in feet). As illustrated in FIG. 5, the dynamometer chart of pump 500 is not a rectangle like the dynamometer chart of pump 400 in FIG. 4. Thus, Equation 2 cannot be applied to accurately determine the pump dynamometer area 500. The ideal pump dynamometer area A _PCI associated with the open tubing string can be determined using Equation 4 below.

Уравнение 4

Equation 4

[0034] In Equation 4, _ATM is the sum of two triangular areas on the sides of a parallelogram (eg, in lbf * in), which can be determined using Equation 5 below.

Уравнение 5

Equation 5

[0035] Value A _TM, defined by equation 5, can be used in Equation 4 to determine the ideal area A _PCI dynamogram pump.

[0036] Another problem that exists that can affect production is pump fill. FIG. 6 illustrates a typical pump 600 dynamometer chart for a well (eg, well 102) with an anchored tubing that is 50% full. The X-axis 602 corresponds to the position of the downhole pump and the Y-axis 604 corresponds to the load on the downhole pump. When pump 126 is not primed, pump 600's dynamometer chart returns during the empty portion of the downstroke until fluid encounters piston 136. In other words, ideally, pump 126 should be completely full of fluid during downstroke. Thus, the pressure of the fluid above and below the piston 136 is the same and therefore the load on the pump 126 during the downstroke is typically zero. However, if pump 126 is not completely filled with fluid, piston 136 carries the fluid column above pump 126 as piston 126 moves downward during downstroke. As soon as the piston 136 abuts against the fluid in the pump 126, the pressure above and below the piston 136 is stabilized and thus the load on the pump 126 becomes zero. Comparing with FIG. 4, the dynamometer chart of the pump 400 in FIG. 4 has a larger area than the dynamometer chart of pump 600 in FIG. 6. The ideal area A _{PCI of the} pump 600 dynamogram can be determined using Equation 6 below.

Уравнение 6

Equation 6

[0037] In Equation 6, AT _TM is the sum of the triangular areas (eg, calculated using Equation 5) and η is the pump fill factor (eg, degree). Thus, Equation 6 combines the pumping behavior with the tubing string movement to accurately determine the pump dynamometer chart area. For anchored wells, the open tubing length L in Equation 5 is zero, giving zero _ATM in Equation 6. Equation 6 can be rearranged to determine the pump fill factor η as shown in Equation 7 below.

Уравнение 7

Equation 7

[0038] In Equation 7, A _PC is the actual area of the integrated dynamometer chart (eg, in lbf * in), which can be determined, for example, using the trapezoid method. Equation 7 provides a means for determining (eg, estimating) the pump fill factor, η, using known parameters (eg, attributes) of the tubing string and the pump dynamogram. Thus, a typical method or process for determining a pump fill rate η may include calculating a surface dynamogram (e.g., a surface dynamogram 200), calculating (e.g., calculating) a pump dynamogram (e.g., a pump 600 dynamogram, which may be based on a surface dynamogram), analyzing pump dynamogram for determining the maximum and minimum position, and maximum and minimum loads (S _max , S _min , F _max , F _min ), integrating the pump dynamogram to determine the true or actual area A _PC , calculating the triangular areas A _TM using equation 5 ( if the tubing string is not anchored) (L, E, and A are known from the tubing string configuration), and calculating the pump fill factor η using equation 7. Such a method can be performed, for example, by the processor 152 of the sucker rod pump controller 146. The pump fill factor η can be determined for each stroke of the pumping unit 100. In some examples pax, the pump fill rate η can be monitored and can be used to control the speed and / or on / off operations of the motor 110. For example, if the pump fill rate η falls below a threshold or target, the speed of the motor 110 can be reduced. This allows relatively more time to fill pump 126 between strokes.

[0039] As described herein, a pump leak occurs when there is a pressure difference across pump 126. Therefore, when the pump dynamogram shows a positive load on pump 126, there is a pressure difference across pump 126. In addition, the leak rate is proportional to the pressure difference across pump 126. Since the pressure difference across the pump is proportional to the load on the pump dynamometer chart, the leak rate is proportional to the load on the pump dynamo chart. The pump leaks on the upstroke because there is a pressure difference across the pump (eg, as indicated by the load on pump 126 during the upstroke). In addition, pump 126 may leak on the downstroke when the fill is less than 100%, since a pressure difference across pump 126 exists when pump 126 is less than 100% full. Taking into account the fact that the discrete values used to calculate the pump dynamometer are distributed equally over time, the amount of fluid leakage LKG can be determined (for example, approximated) using the following equation 8.

) Уравнение 8

) Equation 8

[0040] In Equation 8, LKG is the volume of fluid leaking through the pump (eg, in ³ inches) and C _LKG is the proportionality factor of the leak (eg, in ² / lbf). The term (2,0-η) in Equation 8 accounts for downstroke leakage. If the pump 126 is full (for example, the volume of the wellbore 138 is less than the volume under the piston 136), then the pump fill factor is 1.0 and the term (2.0-η) becomes 1.0. However, if the pump 126 is not completely full, for example 50% full, the pump fill factor is 0.5 and the term (2.0-η) becomes 1.5, which indicates a leak during the half stroke down. ... Once the volume of leakage fluid LKG is known, the net production for the pump _stroke IP _stroke can be determined using Equation 9 below.

Уравнение 9

Equation 9

[0041] Equations 1 and 8 may be combined into Equation 9 to obtain Equation 10 below to determine the net pump _stroke IP _stroke .

Уравнение 10

Equation 10

[0042] In general, the ΔP term in equation 10 can be difficult to estimate from known or measured operating parameters. As described in this document, typical methods and apparatus assume that the differential pressure across the pump, ΔP, is proportional to the pump load. The relationship for determining the value of the instantaneous pressure ΔP _i can be determined using the following equation 11.

Уравнение 11

Equation 11

[0043] In Equation 11, ΔP _i is the instantaneous pressure at the pump (e.g., in lbf / ^in2), F _i is the instant power of the pump (for example, in pound-force), and A _pump is a cross- section of the pump (for example, in inch ² ). To obtain the average or average force F _avg on pump 126 for a completed or full stroke (e.g. upstroke and downstroke), the average force F _avg can be determined using Equation 12 below.

Уравнение 12

Equation 12

[0044] Substituting Equation 12 into Equation 11 yields Equation 13 below.

Уравнение 13

Equation 13

[0045] In Equation 13, ΔP _avg is the average pressure across the pump at the time of the leak (eg, in lbf / in ² ). Substituting Equation 13 into Equation 10 gives Equation 14 below, which provides an accurate way to derive (eg estimate) the net production IP _stroke from a single stroke of a pumping unit.

Уравнение 14

Equation 14

[0046] From Equation 14, production P _observed for a series of strokes of a pumping unit can be estimated using Equation 15 below.

Уравнение 15

Equation 15

[0047] In Equation 15, P _observed is the total observed production during a series of moves (for example, in inch ³ ), and ∑ is the sum of the terms for all moves over the observation period (for example, for two moves, eight moves, etc.) etc.). Equation 15 can be rearranged to determine the Leak Proportionality Factor C _LKG , which gives Equation 16 below.

Уравнение 16

Equation 16

(например, первого члена суммирования) и значение члена

(например, второго члена суммирования) на основании ходов насосной установки в течение периода калибровки. В конце периода калибровки наблюдаемая общая добыча жидкости (нефти и воды) P_observed и члены суммирования

и

могут использоваться в уравнении 16 для определения значения коэффициента пропорциональности утечки C_LKG. Значение коэффициента пропорциональности утечки C_LKG может затем использоваться для вывода или определения добычи для одинарного хода (например, с использованием уравнения 14) или для множества ходов в течение определенного периода времени (например, с использованием уравнения 15). Иными словами, имея коэффициент пропорциональности утечки C_LKG (который можно получить с использованием вышеприведенного типового способа или другого средства), предполагаемая добыча отдельного хода может быть определена с использованием уравнения 14 и значений, полученных из динамограммы скважины. Предполагаемая добыча для отдельных ходов может накапливаться в течение определенного периода времени (например, часа, дня, месяца и т. д.), который может определяться с использованием уравнения 15. [0048] In some examples, a calibration process may be performed to obtain a leakage proportional factor C _LKG . For example, a production well may be connected to a dedicated two-phase or three-phase separator that can measure the production of fluid from the well over a specified period of time (eg, 6 hours, 1 day, etc.) and / or for a specified number of strokes. For example, in FIG. 1, a separator 154 is illustrated that can separate oil from water and gas and determine the volume of oil produced. The processor 152 can measure the required parameters, calculate the pump dynamometer curves (for example, for each stroke), and perform the calculations described herein to determine the value of the term

(for example, the first term of summation) and the value of the term

(for example, the second summation term) based on the strokes of the pumping unit during the calibration period. At the end of the calibration period, the observed total production of liquid (oil and water) P _observed and summation terms

and

can be used in Equation 16 to determine the Leak Proportional Gain C _LKG . The Leak Proportionality Factor C _LKG value can then be used to infer or determine production for a single stroke (eg, using Equation 14) or for multiple strokes over a period of time (eg, using Equation 15). In other words, given the leakage proportionality factor C _LKG (which can be obtained using the above exemplary method or other means), the estimated production of an individual stroke can be determined using Equation 14 and values obtained from the well dynamometer chart. Estimated production for individual moves can accumulate over a period of time (for example, hour, day, month, etc.), which can be determined using Equation 15.

[0049] Equation 13 above provides a means for determining or estimating the differential pressure ΔP across pump 126 using known attributes of pump 126 and pump dynamogram. Using Equation 17 below, you can determine the Pump intake pressure (PIP).

Уравнение 17

Equation 17

[0050] In Equation 17, PIP is the pump inlet pressure (eg, in lbf / in ² ), PDP is the pump outlet pressure (eg, in lbf / in ² ), and ΔP _pump is the differential pressure across the pump (which can be determined using Equation 13). A number of methods can be used to determine (eg estimate) the outlet pressure of a PDP pump. The fluid contained in the production string can be viewed as fluid or as a static vertical column of fluid. In some examples, because the fluid flow is cyclical (for example, reciprocating rod pump systems only pump during the upstroke) and flow rates are relatively low, frictional pressure losses in the vertical column are often neglected. However, changes in density in the fluid column should be considered. For example, a typical method may include triggering at surface at surface outlet pressure (eg, as measured by a transducer) and stepwise calculating the pressure down the tubing string 132 (FIG. 1). An exemplary method or process may include (eg, assuming a constant density over a segment or discrete increment) (1) obtaining estimates of oil, water and gas production rates for a well; (2) obtaining or approximating the relationships for pressure (P), volume (V) and temperature (T) (PVT) of liquid components within reasonable pressure and temperature ranges; (3) measuring or evaluating outlet pressure and surface temperature; (4) using PVT characteristics, together with pressure and temperature estimates, to calculate the density of an assumed mixture of oil, water and gas at outlet pressure and temperature; (5) an assumption of constant density from discrete increments of depth or pressure; (6) calculating or estimating depth, pressure and temperature at the bottom of the discrete increment; (7) determining if the pump depth has been reached using the current design pressure as the pump outlet pressure; and (8) if pump depth has not been reached, return to step 4. In this example, PVT ratios can be estimated using oil and gas gravimetric measurements, empirical correlations, and / or pressure and temperature estimates that can be stored, for example , in memory 150. Additionally or alternatively, a complex state model equation may be used. In some examples, a processor (eg, processor 152) may estimate the pump outlet pressure, estimate the differential pressure across the pump at the end of each stroke (eg, using Equation 13), and apply Equation 17 to obtain a calculated pump inlet pressure.

[0051] In some examples, in such a typical method, the pump inlet pressure measurements may have a relatively large noise contribution (eg, pump inlet pressure estimates for different strokes may vary). In such an example, a proportional-integral-derivative (PID) controller with a damped function or low gain can be used, whereby the processor can perform either on / off or speed control of the pumping system. For example, in on / off control mode, rod pump controller 146 may stop pump 126 (e.g., stop motor 110) and place pumping unit 100 temporarily idle when the design pump inlet pressure falls below the pump inlet pressure threshold for a specified number of strokes. In speed control mode, for example, the rod pump controller 146 may decrease the pump speed if the calculated pump inlet pressure is below a threshold and increase the pump speed if the calculated pump inlet pressure exceeds the threshold.

[0052] While FIG. 1 illustrates an exemplary embodiment of a device 146, one or more elements, methods, and / or devices illustrated in FIG. 1 can be combined, separated, rearranged, omitted, excluded, and / or implemented in any other way. In addition, a typical I / O device 148, a typical memory 150, a typical processor 152, and / or more generally, a typical device 146 of FIG. 1 may be implemented by hardware, software, firmware, and / or any combination of hardware, software, and / or firmware. Thus, for example, any of a typical I / O device 148, a typical memory 150, a typical processor 152, and / or more generally, a typical device 146 of FIG. 1 may be implemented by one or more analog or digital circuits, logic circuits, programmable processors, application specific integrated circuits (ASICs), programmable logic devices (PLDs), and / or programmable logic devices (PLLs). When any of the devices or systems claimed in this patent are interpreted to cover solely software and / or firmware implementation, at least one of the following: a typical I / O device 148, a typical memory 150, and / or a typical processor 152 are clearly defined / defined to contain a tangible machine-readable storage medium or storage disc such as: memory, digital versatile disc (DVD), compact disc (CD), Blu-ray disc, etc., storing software and / or firmware. In addition, the typical arrangement of FIG. 1 may comprise one or more elements, methods and / or devices in addition to or instead of those illustrated in FIG. 1, and / or may contain more than one of any or all of the illustrated elements, methods, and devices.

[0053] Block diagrams representing exemplary embodiments of the device 146 of FIG. 1 are shown in FIG. 7, 8, 9,10A and 10B. The methods of FIG. 7, 8, 9, 10A, and 10B may be implemented by computer readable instructions that contain a program for execution by a processor, such as processor 1112 shown on the exemplary processing platform 1100 discussed below with reference to FIG. 11. The program may be implemented as software stored on a tangible computer-readable storage medium such as: CD-ROM, floppy disk, hard disk, digital versatile disk (DVD), Blu-ray disk, or memory associated with processor 1112, but the entire program and / or portions thereof may alternatively be executed by a device other than processor 1112 and / or implemented as firmware or specialized hardware. In addition, while exemplary methods have been described with reference to the flowcharts illustrated in FIG. 7, 8, 9, 10A, and 10B, many other ways of implementing the generic device 146 may be used in alternatives. For example, the order of the steps may be changed and / or some of the steps described may be changed, eliminated, or combined.

[0054] As mentioned above, the exemplary methods of FIG. 7, 8, 9, 10A, and 10B may be implemented using encoded instructions (e.g., computer-readable and / or machine-readable instructions) stored on a tangible computer-readable storage medium such as: hard disk, flash memory, read only memory (ROM ), compact disc (CD), digital versatile disc (DVD), cache, random access memory (RAM), and / or any other storage device or storage disk that stores information for any period of time (for example, for large periods of time, continuously, for short periods of time, during temporary buffering and / or during data caching). As used herein, the term “tangible computer-readable storage medium” is explicitly defined to include any type of computer-readable memory and / or storage disk, and to exclude propagating signals, and to exclude transmission media. The terms "tangible computer-readable storage medium" and "tangible computer-readable storage medium" are used interchangeably herein. Additionally or alternatively, the exemplary methods of FIG. 7, 8, 9, 10A, and 10B may be implemented using encoded instructions (e.g., computer readable and / or machine readable instructions) stored on a tangible nonvolatile computer readable and / or machine readable storage medium such as: hard disk, flash memory , read-only memory, compact disk, digital versatile disk, cache, random access memory, and / or any other storage device or storage disk on which information is stored for any period of time (e.g., for long periods of time, permanently, for short periods of time, during temporary buffering and / or during data caching). As used herein, the term non-volatile computer-readable storage medium is explicitly defined to include any type of computer-readable storage medium and / or storage disk, and exclude propagating signals, and exclude transmission media. In the context of this document, the use of the phrase "at least" as a transitional term in the preamble of the claims means the possibility of change, just as the term "contains" means the possibility of change.

[0055] FIG. 7 illustrates a typical method 700 for calculating a pump fill factor (eg, degree) for a pumping installation. An exemplary method 700 may be implemented by device 146 (eg, using processor 152) of FIG. 1, for example, to calculate a pump fill rate for pump 126. An exemplary method 700 includes calculating a surface dynamometer chart (block 702). As described herein, the surface dynamogram is obtained from measurements taken at the surface and displays the load on the polished rod versus the position of the polished rod. In FIG. 2 illustrates a typical dynamometer chart of a pump 200 that may be calculated for a typical pumping station 100 of FIG. 1. The surface dynamogram may be computed, for example, by processor 152 of FIG. 1.

[0056] An exemplary method 700 includes calculating a pump dynamometer chart (block 704). As described herein, the pump dynamogram can be calculated using data collected for the surface dynamogram and a mathematical calculation process that simulates the flexibility of a sucker rod string. In FIG. 3, 4, 5, and 6 illustrate typical pump dynamometers that may be calculated for a typical pumping station 100 of FIG. 1. The pump dynamometer chart can be calculated, for example, by processor 152 of FIG. 1.

[0057] Exemplary method 700 includes determining a maximum pump position S _max , a minimum pump position S _min , a maximum pump load F _max, and a minimum pump load F _min from a pump dynamometer chart (block 706). Pump positions and loads may be determined, for example, by processor 152 of FIG. 1.

[0058] The exemplary method 700 of FIG. 7 includes determining if a tubing string (eg, tubing string) of the pumping unit is anchored (block 708). As described in this document, if the tubing string of the pumping unit is not anchored, the tubing string can bend and stretch during operation. As a result, the force on the pump can be weakened at times. For example, in FIG. 4 depicts a typical dynamometer chart of a pump 400 of a well having an anchored tubing string, and FIG. 5 shows a typical dynamometer chart of a pump 500 for a well having an open tubing string. If the tubing string is anchored, the exemplary method 700 includes calculating the ideal area A _{PCI of the} pump dynamometer chart for the anchored tubing string (block 710). Ideal area A _PCI can be based on maximum pump position S _max , minimum pump position S _min , maximum pump load F _max and minimum pump load F _min . For example, the ideal area A _PCI can be calculated using Equation 2. If the tubing is not anchored, the exemplary method 700 includes calculating the ideal area A _{PCI of the} pump dynamometer chart for the open tubing (block 712). Ideal area can be based on maximum pump position S _max , minimum pump position S _min , maximum pump load F _max and minimum pump load F _min , elastic modulus E of the tubing string material, tubing cross-sectional area A _tubing, and length L of the unanchored tubing string. ... For example, the ideal open-string pump dynamometer area A _PCI may be calculated using Equation 4. Processor 152 of FIG. 1 can determine if tubing 136 is anchored or not and can calculate the ideal area A _{PCI of the} pump dynamometer using Equation 4.

[0059] An exemplary method 700 includes calculating the true area A _{PC of a} pump dynamometer chart (block 714). The true area of the pump dynamogram can be calculated using, for example, the trapezium method or any other mathematical formula. The true pump dynamometer area A _PC can be calculated, for example, by processor 152 of FIG. 1. An exemplary method 700 includes determining a pump fill rate η based on the calculated ideal area A _{PCI of the} pump dynamo chart and the true area A _{PC of the} pump dynamo chart (block 716). For example, the pump fill rate η may be determined using Equation 7. The pump fill rate η can be determined, for example, by processor 152 of FIG. 1. Pump fill factor η can be used, among other things, to determine the pump inlet pressure PIP and / or to determine the leak proportional factor C _LKG , which can then be used to more efficiently estimate production and / or control the pumping unit. In some examples, the pump duty factor can be used to control the speed and / or the pump on / off operation. For example, the pump fill rate can be monitored, and when the pump fill rate falls below a target (for example, for one stroke or for a given number of strokes), the pump can be stopped (or reduced in speed) and the well can be left idling to the well casing is filled with production from the reservoir. Therefore, when pumping is resumed (at the end of the shutdown), sufficient fluid may be available to fill the pump.

[0060] FIG. 8 illustrates a typical method 800 for calculating or determining pump inlet pressure. An exemplary method 800 may be implemented by device 146 (eg, using processor 152) of FIG. 1, for example, to determine the PIP inlet pressure of pump 126. An exemplary method 800 includes determining a pump fill rate η (block 802). The pump fill ratio, η, can be determined using the exemplary method 700 of FIG. 7, which may be implemented by the exemplary device 146 of FIG. 1. An exemplary method 800 includes calculating an average pump force F _avg over a period of time that a leak occurs (block 804). The average force F _avg can be based, for example, on the area A _{PC of the} pump dynamometer chart, the maximum pump position S _max , the minimum pump position S _min and / or the pump fill factor η. The pump dynamometer chart area A _PC , the maximum pump position S _max, and the minimum pump position S _min are described with reference to method 700 of FIG. 7. The average force F _avg may be determined using equation 12, which may be implemented, for example, by the exemplary processor 152 of FIG. 1.

[0061] An exemplary method 800 includes calculating an average pressure ΔP _avg across a pump at a time when a leak occurs (block 806). The average pressure ΔP _avg may be determined using Equation 13, which may be implemented, for example, by processor 152 of FIG. 1. In Equation 13, the average pressure ΔP _{avg is} based on the true area A _{PC of the} pump dynamometer chart, the cross-sectional area A _{pump of the} pump, the maximum pump position S _max , the minimum pump position S _min and the pump fill factor η. An exemplary method 800 includes obtaining oil, water, and gas production estimates for a well (block 808). Rate estimates may be obtained, for example, by processor 152 of FIG. 1. Rates may be based on measurements from separator 154. In other examples, rates may be determined based on estimated production, such as determined according to the method of FIG. 10A and 10B and described in this document in more detail.

[0062] The exemplary method 800 of FIG. 8 includes obtaining or approximating relationships for pressure, volume, and temperature of fluid components over pressure and temperature ranges (block 810) (eg, pressure and temperature ranges that are appropriate for well operating conditions). The ratios may be derived or approximated, for example, by processor 152 of FIG. 1. In some examples, relationships are stored in memory 150. An exemplary method 800 includes measuring or estimating outlet pressure and surface temperature (block 812). For example, processor 152 of FIG. 1 can receive measurement data via I / O 148 and determine outlet pressure and surface temperature.

[0063] An exemplary method 800 includes using pressure, volume, and temperature characteristics, along with pressure and temperature measurements / estimates, to calculate the density of an assumed oil / water / gas mixture at outlet pressure and temperature (block 814). Density can be calculated, for example, by processor 152 of FIG. 1. An exemplary method 800 includes estimating a constant density from a discrete increment of depth or pressure (block 816), and calculating the depth, pressure, and temperature at the bottom of the discrete increment (step 818). The discrete increment can be any increment (for example, 1 mm). Depth, pressure, and temperature values can be calculated, for example, by processor 152 of FIG. 1.

[0064] An exemplary method 800 includes determining a state when a pump depth has been reached (block 820). In other words, method 800 includes determining whether the increment is the last or lowest well increment. If not, the exemplary method 800 includes using pressure, volume, and temperature characteristics to calculate density and calculate depth, pressure, and temperature values at the bottom of the next discrete increment (blocks 814-818). This method can be continued until the pump depth is reached. If pump depth has been reached, method 800 includes using the current design pressure as the pump outlet pressure (block 822) (eg, the pressure value calculated at block 818) and calculating the pump inlet pressure based on the calculated pump differential pressure and the outlet pressure. pump (block 824). The pump inlet pressure may be calculated using equation 17, which may be implemented, for example, by processor 152 of FIG. 1.

[0065] FIG. 9 is a flow chart depicting an exemplary method 900 that may be used to operate a pumping unit based on pump inlet pressure. An exemplary method 900 may be implemented by device 146 (eg, using processor 152) of FIG. 1, for example, to operate pump 126 above or below a threshold inlet pressure and / or pressure range. An exemplary method 900 includes determining a pump inlet pressure (block 902), which may be determined using the exemplary method 800 of FIG. 8. An exemplary method 900 includes comparing a pump inlet pressure to a pump inlet pressure threshold (block 904). The pump inlet pressure can be in a range (for example, have an upper limit and a lower limit). The pump inlet pressure can be set by the operator. For example, processor 152 of FIG. 1 may determine the PIP inlet pressure of pump 126 and compare the PIP inlet pressure to a pump inlet pressure threshold.

[0066] An exemplary method 900 includes determining if a pump inlet pressure is within a pump inlet pressure threshold (block 906). For example, the pump inlet pressure can be higher than the allowable or threshold pump inlet pressure. If the pump inlet pressure is not within a pump inlet pressure threshold, an exemplary method 900 includes starting or stopping the pump and / or changing the pump speed (block 908). For example, the device 146 of FIG. 1 may be used to control engine 110 to increase or decrease the speed of engine 110. As described herein, some examples may require the pump to operate above a set inlet pressure threshold, which may, for example, allow lighter hydrocarbons to remain in the liquid phase. An exemplary method 900 includes determining whether to continue monitoring the well (block 910). If monitoring is to continue, sample method 900 may be repeated. Otherwise, the typical method 900 may end.

[0067] FIG. 10A and 10B, a flow chart is illustrated representing an exemplary method 1000 that may be used to estimate production of an oil well. Exemplary method 1000 may be implemented by device 146 (eg, using processor 152) of FIG. 1, for example, to estimate production from well 102 with pumping unit 100. A typical method 1000 includes obtaining pump parameters or attributes such as pump diameter, pump cross-sectional area A _pump , modulus E of tubing string material, and / or length L of any unanchored tubing strings (step 1002). Parameters or attributes may be obtained, for example, by processor 152 of FIG. 1. At step 1004, a process for directly measuring fluid production from a well (eg, well 102 of FIG. 1) begins for a first predetermined time period and / or during a first predetermined number of strokes (step 1004). Fluid produced from a well (eg, well 102) is directly measured for one or more strokes of a pumping unit (eg, pumping unit 100) (block 1006). In some examples, fluid is measured directly using a well test separator (eg, separator 154 of FIG. 1). An exemplary method 1000 includes determining if the pumping unit has completed a stroke (block 1008). For example, processor 152 may determine if pumping unit 100 has completed a stroke. In some examples, processor 152 determines that pumping station 100 completes stroke based on feedback received from a sensor near crank arm 116. If pumping station stroke has not been completed, the method continues to directly measure fluid produced from the well (block 1006) ...

[0068] If the pumping unit has completed its stroke (determined at 1008), the exemplary method 1000 includes calculating the pump dynamometer chart based on, for example, the determined surface dynamogram and / or data collected for the surface dynamogram (block 1010). The pump dynamometer chart can be calculated, for example, by processor 152 of FIG. 1. Typical method 1000 includes determining a maximum pump position S _max , a minimum pump position S _min , a maximum pump load F _max, and a minimum pump load F _min from a pump dynamometer chart (block 1012). Pump positions and loads may be determined, for example, by the typical processor 152 of FIG. 1. An exemplary method 1000 includes determining the area A _{PC of a} pump dynamometer chart (block 1014). For example, processor 152 may determine the area A _{PC of a} pump dynamometer using a trapezoidal method.

для хода(ов), произошедшего(ых) в течение первого заданного периода времени, а второе значение суммирования может рассчитываться с использованием

для хода(ов), произошедшего(ых) в течение первого заданного периода времени. Первое и второе значения суммирования могут быть определены, например, процессором 152 по фиг. 1.[0069] An exemplary method 1000 includes determining a pump fill rate η (block 1016). The pump fill ratio, η, may be determined using the exemplary method 700 of FIG. 7. Exemplary method 1000 includes calculating a first summation value and a second summation value (block 1018) for pump stroke dynamometer (s) that occurred during a first predetermined time period and / or a first predetermined number of strokes. For example, the first summation value can be calculated using

for the move (s) occurring during the first predetermined time period, and the second summation value can be calculated using

for the move (s) occurring during the first specified time period. The first and second summation values may be determined, for example, by processor 152 of FIG. 1.

[0070] An exemplary method 1000 includes determining whether a first predetermined period of time has elapsed and / or whether a first predetermined number of strokes of the pumping unit have occurred (block 1020). For example, processor 152 of FIG. 1 may determine whether the first predetermined time period has elapsed and / or whether the first predetermined number of moves has occurred. If the first predetermined period of time has not elapsed and / or if the predetermined number of strokes has not occurred, measurement of the fluid produced from the well continues (step 1006).

[0071] If the first predetermined time period has elapsed and / or if a predetermined number of strokes have occurred, an exemplary method 1000 includes determining the total fluid production P _observed for the first predetermined time period and / or for the first predetermined number of strokes (block 1022). Typical method 1000 includes determining a leakage proportional factor C _LKG (block 1024). Leakage proportionality factor C _LKG may be based on pump parameters (e.g., obtained in step 1002), total fluid production P _observed during the first specified time period and / or during the first specified number of strokes (for example, obtained in step 1022), and / or a first summation value and a second summation value (eg, obtained at step 1020). For example, the leakage aspect ratio C _LKG may be determined using Equation 16, which may be implemented by the exemplary processor 152 of FIG. 1.

[0072] The exemplary method 1000, which continues with FIG. 10B includes determining (eg, outputting) production of the pumping unit during normal operation and / or while the pumping unit is continuously operating for a second predetermined period of time (step 1026). The second predetermined time period may be, for example, an hour, day, week, month, etc. An exemplary method 1000 includes determining if a pumping unit has completed a stroke (block 1028) (e.g., a complete cycle including an up stroke and a down stroke ). If the pumping unit has not completed the stroke, method 1000 iteratively determines if the stroke is complete. If the pumping unit has completed its stroke (eg, as determined by processor 152), the exemplary method 1000 includes calculating a pump dynamometer chart (block 1030). The pump dynamogram can be based, for example, on a specific surface dynamogram. The pump dynamometer chart can be calculated, for example, by processor 152 of FIG. 1.

[0073] An exemplary method 1000 includes determining a maximum pump position S _max , a minimum pump position S _min , a maximum pump load F _max, and a minimum pump load F _min from a pump dynamometer chart (block 1032). Pump positions and loads may be determined, for example, by the typical processor 152 of FIG. 1. An exemplary method 1000 includes determining the area A _{PC of a} pump dynamometer chart (block 1034). For example, processor 152 may determine the area A _{PC of a} pump dynamometer using a trapezoidal method. Typical method 1000 includes determining a pump fill rate η (block 1036). The pump fill ratio, η, may be determined using the exemplary method 700 of FIG. 7. For example, processor 152 may determine a pump duty ratio η using Equation 7.

[0074] An exemplary method 1000 includes determining an estimated production stroke of a pumping unit (block 1038). The production of a pumping unit may be based on pump parameters (eg, obtained at 1002), a pump fill rate η (eg, obtained at 1036) and / or a leakage proportional factor C _LKG (eg, obtained at 1024). For example, IP _stroke production may be determined using Equation 14, which may be implemented by processor 152 of FIG. 1. An exemplary method 1000 includes determining whether a second predetermined time period has elapsed and / or whether a second predetermined number of moves has occurred (block 1040). If the second predetermined time period has not elapsed and / or if the second predetermined number of strokes has not occurred, the typical method 1000 proceeds to block 1028, in which the method 1000 continues to determine if the pumping unit has completed another stroke. If the second predetermined time period has elapsed and / or if a second predetermined number of strokes have occurred, the exemplary method 1000 includes summing production from the traverse (s) (block 1042). The total production P _{observed of the} total stroke (s) can be determined, for example, using Equation 15. The total production P _observed can be determined, for example, by the processor 152 of FIG. 1. Typical method 1000 can be repeated as needed. Otherwise, the typical method 1000 may end.

[0075] FIG. 11 is a block diagram of an exemplary processing platform 1100 capable of executing instructions for implementing the methods of FIG. 7, 8, 9, 10A and 10B and / or to implement the device 146 of FIG. 1. Processor platform 1100 can be, for example, a server, personal computer, mobile device (eg, cell phone, smartphone, tablet such as iPad ^™ ), personal digital assistant (PDA), Internet access device, or computing device any other type.

[0076] The processor platform 1100 of the illustrated example includes a processor 1112. The processor 1112 of the illustrated example is hardware. For example, processor 1112 can be implemented in one or more integrated circuits, logic circuits, microprocessors, or controllers of any desired family or manufacturer.

[0077] The processor 1112 of the illustrated example includes a local memory 1113 (eg, cache memory). Processor 1112 of the illustrated example communicates with main memory, including volatile memory 1114 and nonvolatile memory 1116, via bus 1118. Nonvolatile memory 1114 may be implemented using synchronous dynamic random access memory (SDRAM), a dynamic random access memory ( DRAM), RAMBUS dynamic random access memory (RDRAM), and / or any other type of random access memory device. Nonvolatile memory 1116 can be implemented using flash memory and / or other desired type of memory device. Access to the main memory 1114, 1116 is regulated by the memory controller.

[0078] The processor platform 1100 of the illustrated example also includes an interface circuit 1120. The interface circuit 1120 may be implemented using any type of interface standard such as an Ethernet interface, a universal serial bus (USB), and / or a PCI express serial interface.

[0079] In the illustrated example, one or more input devices 1122 are coupled to interface circuitry 1120. Input device (s) 1122 allows (s) a user to enter data and commands into processor 1112. Input device (s) may be implemented, for example, with using an audio sensor, microphone, camera (camera or camcorder), keyboard, button, mouse, touch screen, touchpad, trackball, isopoint and / or speech recognition system.

[0080] One or more output devices 1124 are also coupled to interface circuit 1120. Output devices 1124 may be implemented, for example, with display devices (eg, light emitting diode (LED), organic light emitting diode (OLED), liquid crystal display, electronic display). ray tube (CRT), touch screen, tactile output, printer and / or speakers). Thus, the interface circuit 1120 of the illustrated example typically includes a graphics driver card, a graphics driver chip, or a graphics driver processor.

[0081] The interface circuit 1120 of the illustrated example also includes a communication device, such as a transmitter, receiver, transceiver, modem, and / or network interface card, for communicating with external machines (e.g., computing devices of any kind) over a network 1126 (e.g. , Ethernet connections, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone systems, etc.).

[0082] The processing platform 1100 of the illustrated example also includes one or more mass storage devices 1128 for storing software and / or data. Examples of such mass storage devices 1128 include floppy disks, hard disks, CDs, Blu-ray disks, RAID systems, and versatile digital disks (DVDs).

[0083] Coded instructions 1132 for implementing the methods of FIG. 7, 8, 9, 10A, and 10B may be stored in mass storage 1128, volatile memory 1114, nonvolatile memory 1116, and / or removable tangible computer-readable storage media such as a CD or DVD.

[0084] From the foregoing, it should be understood that the methods, devices and articles described above relate to determining the production of a downhole reciprocating pump, for example, by linking the work performed by a pumping unit on a sucker rod string and the work used to lift one units of volume of fluid from the well. Using this relationship, the work performed by the pumping unit during a single stroke of the pumping unit can be used to estimate the amount of fluid produced during the stroke. Estimated production for each stroke can be aggregated over a period of time (eg, hourly, daily, monthly, etc.) to derive, estimate and / or determine the estimated production for a pumping unit.

[0085] In at least some examples, the rod pump controller does not calculate the dynamometer chart of the downhole pump. Thus, the examples described herein may be included in a medium to low computing power computing platform. Using the examples described herein, it is not necessary to analyze the dynamometer chart of the downhole pump to determine the full stroke, fluid load, or other similar parameters from the downhole dynamogram. In at least some examples, the leak test is not performed because the leak proportionality factor is determined using calculations associated with the well test. The examples described in this document can be implemented in a field controller.

[0086] An exemplary method disclosed herein includes measuring the amount of fluid produced from a well by a pumping unit over a given period of time, as well as determining the first areas of the first pump dynamometer curves for a given period of time. The typical method also includes summing the first areas and, based on the amount of produced fluid and the summed first areas, determining the proportionality factor for the leakage of the downhole pump in the pumping unit.

[0087] In some examples, the method also includes determining the second area of the second pump dynamometer while continuously operating the pumping unit. In some examples, the method also includes determining the total amount of fluid produced during the stroke of the pumping unit based on the leakage aspect ratio and the second area. In some examples, measuring the amount of fluid produced includes measuring the fluid produced in a separator using a well test separator.

[0088] In some examples, determining the first areas of the first pump dynamos for a predetermined period of time includes using a rod pump controller to determine the first areas. In some examples, the method also includes determining the second areas of the second pump dynamometer curves while continuously operating the pumping unit for a second predetermined period of time. In some examples, the method also includes determining the total amount of fluid produced during a second predetermined time period based on the aspect ratio and the second areas. In some examples, the leakage proportional constant is additionally determined based on the differential pressure across the downhole pump of the pumping unit.

[0089] An exemplary device disclosed herein includes a housing for use with a pumping unit and a processor housed within the housing. The processor is designed to determine the first areas of the first pump dynamometer charts for a given period of time, summarize the first areas and, based on the amount of fluid produced by the downhole pump of the pumping unit during a given period of time from the well, and the summed first areas, determine the proportionality coefficient of the downhole pump leakage.

[0090] In some examples, the processor is configured to determine the second area of the second pump dynamometer chart during continuous operation of the pumping unit. In some examples, the processor is designed to determine the total amount of fluid produced during the stroke of the pumping unit based on the proportionality factor of the leak and the second area. In some examples, the device includes a rod pump controller. In some examples, the processor is configured to determine the second areas of the second pump dynamometer curves while continuously operating the pumping unit for a second predetermined period of time. In some examples, the processor is configured to determine the total amount of fluid produced during a second predetermined time period based on the aspect ratio and the second areas. In some examples, the processor is designed to additionally determine the leak proportional factor based on the differential pressure across the downhole pump of the pumping unit.

[0091] Another exemplary method disclosed herein includes measuring a first amount of fluid produced from a well by a pump during a first pump stroke, calculating a first pump dynamometer chart based on the first stroke, determining a first area of a first pump dynamometer chart, and determining a pump leakage proportional factor by based on the first amount of produced fluid and the first area. The exemplary method also includes calculating a second pump dynamometer chart based on the second pump stroke, determining a second area of the second pump dynamometer chart, and determining a second amount of fluid produced by the pump during the second stroke based on the leak proportionality factor and the second area.

[0092] In some examples, the method includes determining a first pump fill rate for the pump during a first stroke. In such an example, the leakage proportional factor is additionally based on the first pump fill factor. In some such examples, the method includes determining the ideal area of the first pump dynamometer chart. The first pump fill factor is based on the ratio of the determined first area of the first pump dynamometer to the ideal area of the first pump dynamogram. In some examples, the method includes determining if the pump tubing is anchored. In some examples, if the tubing string is not anchored, the ideal area of the first pump dynamometer is based on the modulus of elasticity of the tubing string material, the pump cross-sectional area, and the length of the open tubing string.

[0093] In some examples, the method includes determining a second pump fill rate for the pump during a second stroke. In such an example, the second fluid produced is additionally based on a second pump fill factor.

[0094] In some examples, the method includes determining a differential pressure across a pump during a first stroke based on a first fill rate of the pump. In such an example, the Leak Proportional Gain is additionally determined based on the differential pressure across the pump.

[0095] In some examples, the first amount of produced fluid is measured using a separator. In some examples, the method includes calculating a third pump dynamometer chart based on a third pump stroke, determining a third area of a third pump dynamometer chart, determining a third amount of fluid produced by the pump during a third stroke based on a leak proportionality factor and a third area, and summing the second amount and the third amount to determine the total amount of fluid produced by the pump during the second and third strokes.

[0096] Another exemplary device disclosed herein includes a housing to be used with a pumping unit having a downhole pump and a processor located in the housing. The processor of a typical device is designed to determine the first area of the first pump dynamometer chart based on the first pump stroke, determine the pump leakage proportionality factor based on the first amount of liquid produced by the pump during the first pump stroke and the first area, determine the second area of the second pump dynamometer chart based on the second stroke pump, and determining the second amount of liquid produced by the pump during the second stroke, based on the proportionality factor of the leak and the second area.

[0097] In some examples, the device includes a separator. The separator is designed to measure the first amount of liquid produced by the pump during the first stroke. In some examples, the processor is designed to determine the first pump fill rate for the pump during the first stroke. In such an example, the leakage proportional factor is additionally based on the first pump fill factor. In some of these examples, the processor is designed to determine the second pump fill rate for the pump during the second stroke. In such an example, the second amount of produced fluid is further based on the first fill rate of the pump. In some of these examples, the processor is designed to determine the pump inlet pressure during the second stroke based on the second fill rate of the pump. In some examples, the device contains a motor to drive the pump. In such an example, the processor is designed to control the motor speed based on the pump inlet pressure.

[0098] This document describes a typical tangible computer-readable storage medium containing commands that, when executed, cause the machine to at least calculate the first pump dynamometer chart based on the first stroke of the downhole pump, determine the first area of the first pump dynamometer chart, and determine the pump leakage proportional factor based on the first amount of liquid produced by the pump during the first stroke, and the first area. The commands also cause the machine to calculate the second pump dynamometer chart based on the second pump stroke and to determine the second amount of fluid produced by the pump during the second stroke based on the leakage aspect ratio and the second area.

[0099] In some examples, the commands, when executed, further cause the machine to determine the first pump duty ratio for the pump during the first stroke. In such an example, the leakage proportional factor is additionally based on the first pump fill factor. In some examples, the commands, when executed, additionally force the machine to determine a second pump duty ratio for the pump during the second stroke. In such an example, the second fluid produced is additionally based on a second pump fill factor. In some examples, the commands, when executed, additionally force the machine to determine the ideal area of the second pump dynamometer chart. In such an example, the second pump load factor is based on the ratio of the determined second area of the second pump dynamometer to the ideal area of the second pump dynamometer. In some of these examples, the commands, when executed, further cause the machine to determine the differential pressure across the pump during the second stroke based on the second fill rate of the pump.

[00100] Although this document discloses certain typical methods, devices and products, the scope of this patent is not limited to them. On the contrary, the present patent covers all methods and articles explicitly falling within the scope of the claims of the present patent.

Claims (42)

1. A method for determining the production volume of downhole pumps, including: measuring the first amount of fluid produced from the well by the pump during the first pump stroke; calculating the first pump dynamometer chart based on the first stroke; determination of the first area of the first dynamometer chart of the pump; determining the proportional factor of the pump leakage based on the first amount of produced fluid and the first area; calculating a second pump dynamometer chart based on the second pump stroke; determination of the second area of the second dynamogram of the pump; and determination of the second amount of liquid produced by the pump during the second stroke, based on the proportionality coefficient of the leak and the second area. 2. The method of claim 1, further comprising determining a first pump fill ratio for the pump during the first stroke, wherein the leakage proportionality factor is further based on the first pump fill ratio. 3. A method according to any one of the preceding claims, further comprising determining an ideal area of the first pump dynamometer, wherein the first pump fill factor is based on the ratio of the determined first area of the first pump dynamometer to the ideal area of the first pump dynamometer. 4. A method according to any one of the preceding claims, further comprising determining whether the pump tubing is anchored. 5. A method according to any of the preceding claims, characterized in that if the tubing is not anchored, the ideal area of the first pump dynamometer is based on the modulus of elasticity of the tubing material, the pump cross-sectional area and the length of the unanchored tubing. 6. A method as claimed in any one of the preceding claims, further comprising determining a second pump fill rate for the pump during the first stroke, wherein the second fluid produced is further based on a second pump fill rate. 7. A method as claimed in any one of the preceding claims, further comprising determining a differential pressure across the pump during the first stroke based on a first fill rate of the pump, wherein the leakage proportionality factor is further determined based on the differential pressure across the pump. 8. A method according to any of the preceding claims, characterized in that the first amount of produced liquid is measured using a separator. 9. A method according to any of the preceding claims, further comprising: calculating a third pump dynamometer chart based on the third pump stroke; determination of the third area of the third dynamogram of the pump; determining the third amount of liquid produced by the pump during the third stroke, based on the proportionality factor of the leak and the third area; and adding the second amount and the third amount to determine the total amount of fluid produced by the pump during the second and third strokes. 10. A device for determining the volume of production of downhole pumps, containing: a casing for use with a pumping unit having a downhole pump; and a processor located in a housing, the processor being designed to determining the first area of the first pump dynamometer chart based on the first pump stroke; determining a pump leakage proportional factor based on the first amount of liquid produced by the pump during the first stroke and the first area; determining the second area of the second pump dynamometer chart based on the second pump stroke; and determining the second amount of liquid produced by the pump during the second stroke, based on the proportionality factor of the leak and the second area. 11. The apparatus of claim 10, further comprising a separator, the separator being adapted to measure a first amount of liquid produced by the pump during the first stroke. 12. An apparatus as claimed in any one of the preceding claims, wherein the processor is configured to determine a first pump fill rate for the pump during the first stroke, wherein the leakage proportional factor is further based on the first pump fill rate. 13. An apparatus according to any one of the preceding claims, wherein the processor is configured to determine a second pump fill rate for the pump during the second stroke, wherein the second amount of produced fluid is further based on the second pump fill rate. 14. An apparatus according to any of the preceding claims, wherein the processor is configured to determine the pressure at the pump inlet during the second stroke based on the second fill rate of the pump. 15. An apparatus as claimed in any one of the preceding claims, further comprising a motor for controlling the pump, a processor for controlling the speed of the motor based on the pressure at the inlet of the pump. 16. A tangible computer-readable storage medium containing commands that, when executed, force the machine to perform the following steps, which serve to determine the volume of production of downhole pumps: calculate the first pump dynamometer chart based on the first stroke of the downhole pump; determine the first area of the first pump dynamometer chart; determine the proportionality factor of the pump leakage based on the first amount of liquid produced by the pump during the first stroke and the first area; calculate the second pump dynamometer chart based on the second pump stroke; and determine the second amount of fluid produced by the pump during the second stroke based on the proportionality factor of the leak and the second area. 17. The tangible computer-readable storage medium of claim 16, wherein the commands, when executed, further cause the machine to determine a first pump fill rate for the pump during the first stroke, wherein the leakage proportionality factor is further based on the first pump fill factor. 18. The tangible machine-readable storage medium of any one of the preceding claims, wherein the instructions further cause the machine to determine a second pump fill rate for the pump during a second stroke, the second production fluid being further based on the second pump fill rate. 19. The tangible machine-readable storage medium according to any one of the preceding claims, wherein the commands further cause the machine to determine the ideal area of the second pump dynamometer chart, the second pump filling ratio based on the ratio of the determined second area of the second pump dynamometer chart to the ideal area of the second pump dynamometer chart. 20. The tangible computer-readable storage medium of any one of the preceding claims, wherein the commands, when executed, further cause the machine to determine a differential pressure across the pump during the second stroke based on the second fill rate of the pump.

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