EP3314087A1 - Procédés et appareil de détermination de la production de pompes de fond de trou - Google Patents

Procédés et appareil de détermination de la production de pompes de fond de trou

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Publication number
EP3314087A1
EP3314087A1 EP16738945.1A EP16738945A EP3314087A1 EP 3314087 A1 EP3314087 A1 EP 3314087A1 EP 16738945 A EP16738945 A EP 16738945A EP 3314087 A1 EP3314087 A1 EP 3314087A1
Authority
EP
European Patent Office
Prior art keywords
pump
stroke
card
area
during
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Granted
Application number
EP16738945.1A
Other languages
German (de)
English (en)
Other versions
EP3314087B1 (fr
Inventor
Thomas Matthew MILLS
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Bristol Inc
Original Assignee
Bristol Inc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US14/753,335 external-priority patent/US10352149B2/en
Application filed by Bristol Inc filed Critical Bristol Inc
Publication of EP3314087A1 publication Critical patent/EP3314087A1/fr
Application granted granted Critical
Publication of EP3314087B1 publication Critical patent/EP3314087B1/fr
Active legal-status Critical Current
Anticipated expiration legal-status Critical

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E21B43/121—Lifting well fluids
    • E21B43/126—Adaptations of down-hole pump systems powered by drives outside the borehole, e.g. by a rotary or oscillating drive
    • E21B43/127—Adaptations of walking-beam pump systems
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/008—Monitoring of down-hole pump systems, e.g. for the detection of "pumped-off" conditions
    • E21B47/009—Monitoring of walking-beam pump systems
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
    • F04B—POSITIVE-DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS
    • F04B51/00—Testing machines, pumps, or pumping installations
    • G—PHYSICS
    • G16—INFORMATION AND COMMUNICATION TECHNOLOGY [ICT] SPECIALLY ADAPTED FOR SPECIFIC APPLICATION FIELDS
    • G16Z—INFORMATION AND COMMUNICATION TECHNOLOGY [ICT] SPECIALLY ADAPTED FOR SPECIFIC APPLICATION FIELDS, NOT OTHERWISE PROVIDED FOR
    • G16Z99/00—Subject matter not provided for in other main groups of this subclass

Definitions

  • This disclosure relates generally to downhole pumps and, more particularly, to methods and apparatus to determine production of downhole pumps.
  • Downhole pumps are used to pump fluid from a formation by moving a piston relative to a bore. Clearance is provided between the piston and the bore to ensure that downhole debris does not negatively affect the performance of the downhole pump. However, this clearance allows for leakage between the piston and the bore. Further, in some instances the pump may not be completely full when pumping. As a result, pump fillage affects the amount of fluid produced by a pump.
  • FIG. 1 shows a pumping unit including an example apparatus used to determine the production of a well in accordance with the teachings of this disclosure.
  • FIG. 2 shows an example surface dynamometer card that may be produced in accordance with the teachings of this disclosure.
  • FIG. 3 shows an example pump dynamometer card that can be produced in accordance with the teachings of this disclosure.
  • FIG. 4 shows an example pump dynamometer card produced by a pumping unit having anchored tubing.
  • FIG. 5 shows an example pump dynamometer card produced by a pumping unit having unanchored tubing.
  • FIG. 6 shows an example pump dynamometer card produced by a pumping unit in which the pump is not full during the down stroke.
  • FIG. 7 is a flowchart representative of an example method of determining a pump fillage factor and which may be implemented with the example apparatus of FIG. 1.
  • FIG. 8 is a flowchart representative of an example method of calculating pump intake pressure and which may be implemented with the example apparatus of FIG. 1.
  • FIG. 9 is a flowchart representative of an example method of controlling a pumping unit based on pump intake pressure and which may be implemented with the example apparatus of FIG. 1.
  • FIGS. 10A and 10B are a flowchart representative of an example method of determining production of a pumping unit and which may be implemented with the example apparatus of FIG. 1.
  • FIG. 11 is a processor platform to implement any of the example methods of FIGS. 7, 8, 9 or 10A and 10B and/or the example apparatus of FIG. 1.
  • An oilfield downhole reciprocating pump (e.g., a rod pump) is often considered to be a positive displacement pump because a plunger or piston of a known diameter travels a known (or calculable) distance with each stroke. It is desired to use a pump as a meter to approximate the daily production from a well by relating the number of pump strokes during the day and the pump geometry to an inferred production quantity. In other words, because the displacement volume of the pump is known (or calculable), it is desired to use the number of strokes during a time period to infer a volume of liquid produced.
  • downhole oil pumps do not perform as true positive displacement pumps because the pumps are typically designed with significant clearance between the piston and a barrel through which the piston reciprocates, resulting in leakage or slip.
  • information associated with a downhole reciprocating pump may be used to approximate production from a corresponding well.
  • production can be estimated based on the area of a pump and the distance of the pump stroke, which equates to an estimated displacement volume for each stroke.
  • Pump fillage refers to the amount of fluid in a barrel of the pump (e.g., between the piston and a bottom of the barrel). If the barrel of the pump is not completely full when the piston moves downward during the downstroke, then the volume of the liquid pumped by the piston in the upstroke is not the same as the displacement volume of the pump.
  • the methods and apparatus disclosed herein may be used to determine a pump fillage factor (e.g., a fraction), which is useful for a number of rod pump control applications.
  • a pump fillage factor is a highly desirable process variable for rod pump speed control and/or rod pump on/off control.
  • the pump speed may be decreased when pump fillage factor is below a target value (e.g., a set point, a threshold) and increased when pump fillage factor is above the target value.
  • a target value e.g., a set point, a threshold
  • the pump fillage factor can be monitored and when the pump fillage factor falls below a target value for a specified number of strokes, the pump can be stopped and the well can be left in idle to allow the well casing to be filled by the producing formation. Therefore, when pumping is resumed (at the end of idle time), sufficient fluid may be present to fill the pump.
  • downhole pumps are designed with a clearance or gap between the piston and the barrel or tube within which the piston reciprocates. Therefore, on the upstroke (e.g., when a pressure difference across the piston exists), leakage occurs between the pump and the barrel. As a result, the volume of fluid actually pumped is less than the predicted or estimated volume.
  • the example methods and apparatus disclosed herein may be used to determine a leakage proportionally constant that may be used to more accurately predict the volume of oil produce in each stroke.
  • the pump fillage fraction or factor is also used to determine the leakage proportionally constant. Therefore, the example methods and apparatus disclosed herein may be used to determine pump fillage and leakage, which can then be used to more accurately infer production.
  • production from the well may be inferred based on the number of strokes of the pumping unit, the geometry of the downhole pump, the example leakage proportionality constant and/or the pump fillage factor.
  • a stroke refers to a complete cycle including an upstroke and a down stroke.
  • an operator or owner may desire to operate the well at or near "pumpoff," which is the point at which the available liquid in the wellbore is marginally adequate to fill the pump.
  • pumpoff the point at which the available liquid in the wellbore is marginally adequate to fill the pump.
  • operating a well near pumpoff results in the lowest practical producing bottom hole pressure.
  • inflow to the wellbore increases as bottom hole pressure declines. Therefore, operating the well at or near pumpoff generally results in maximum production from the well.
  • an operator may desire to operate a well at a specified wellbore pressure other than at pumpoff. This strategy may provide superior reservoir management because it enables lighter hydrocarbon components to remain in solution with the liquid phase as the products flow toward the wellbore.
  • the effective permeability to liquids is increased. In some instances, this approach results in higher overall recovery of hydrocarbons (although in some instances the recovery may take a longer period of time).
  • a specified downhole pressure value e.g., a set point, a threshold
  • some method of measuring or estimating wellbore (pump intake) pressure is needed.
  • Some instrumentation products are available to directly measure these values. However, these products are generally expensive and operationally complex to install.
  • the example methods and apparatus disclosed herein provide a technique for determining the pressure difference across the pump using the pump fillage factor described above. As a result, the intake pressure of the pump can be determined and used to control the speed of the pump.
  • the intake pressure of the pump may be used for rod pump speed control and rod pump on/off control. In other words, the pump speed may be decreased or increased and/or the pump may be stopped or started based on the intake pressure of the pump.
  • FIG. 1 shows an example pumping unit 100 that may be used to produce oil from an oil well 102.
  • the pumping unit 100 includes a base 104, a Sampson post 106 and a walking beam 108.
  • the pumping unit 100 includes a motor or engine 110 that drives a belt and sheave system 112 to rotate a gear box 114 and, in turn, rotate a crank arm 116 and a counterweight 118.
  • a pitman 120 is coupled between the crank arm 116 and the walking beam 108 such that rotation of the crank arm 116 moves the pitman 120 and the walking beam 108.
  • the walking beam 108 pivots about a pivot point and/or saddle bearing 122, the walking beam 108 moves a horse head 124 to provide reciprocating movement to a downhole pump 126 via a bridle 128, a polished rod 130, a tubing string 132 and a rod string 134.
  • the reciprocating movement of the horse head 124 moves a piston 136 of the pump 126 within a barrel 138 (e.g., a bore, a casing, a housing, etc.) of the pump 126 to draw liquid from the surrounding formation 140 (labeled as F).
  • a stationary valve 142 e.g., a lower valve
  • the piston 136 includes a traveling valve 144 (e.g., an upper valve) that is in the closed position.
  • the piston 126 pushes the fluid in the tubing 132 above the piston 136 to the surface.
  • the traveling valve 144 of the piston 126 opens, which enables the fluid in the barrel 138 to flow through the valve 144 and into the tubing 138 above the piston 126.
  • the stationary valve 142 is closed.
  • the piston 126 then moves upward during a subsequent upstroke to push the fluid in the tubing 132 toward the surface, and so forth.
  • a clearance or gap is provided between the piston 136 and the bore 138.
  • the clearance reduces the volume of fluid produced by the pump 126 during each stroke of the pumping unit 100.
  • the pumping unit 100 includes an example apparatus and/or rod pump controller 146.
  • data from and/or associated with the pumping unit 100 is received by an input/output (I/O) device 148 of the rod pump controller 146 and stored in a memory 150 that is accessible by a processor 152.
  • I/O input/output
  • the processor 152 can perform processes to determine, for example, an example pump fillage factor (e.g., based on the volume of fluid contained in the pump 126), an intake pressure of the pump 126, an example leakage proportionality constant (e.g., in /lbf), the volume of fluid leaked through the pump 126 (e.g., in ) and/or the net fluid produced during a stroke of the pumping unit 100 and/or a given time period.
  • the components 148, 150, 152 of the apparatus 146 are disposed within a housing 147, which may be located at the site of the pumping unit 100. In other examples the apparatus 146 may be located in a remote location (e.g., at a base station or control room).
  • a traditional diagnostic tool used with reciprocating rod pumps is called the dynamometer card, which is a plot of load (e.g., force) versus position (e.g., linear displacement) for a single stroke of a pumping unit.
  • load e.g., force
  • position e.g., linear displacement
  • Two types of dynamometer cards are typically used.
  • the first type of dynamometer card is the surface card, which is based upon measurements taken at the surface and displays polished rod load versus polished rod position.
  • the second type of dynamometer card is referred to as the pump dynamometer card and is computed using data collected for the surface dynamometer card and a mathematical computation process that models the flexibility of the sucker rod string.
  • FIG. 2 shows an example surface dynamometer card 200 that can be generated in accordance with the teachings of this disclosure using data associated with the vertical displacement of the polished rod 130 versus time and data associated with tension on the polished rod 130 versus time.
  • the surface dynamometer card 200 represents a scenario in which the downhole pump 126 is operating normally with adequate liquid to pump.
  • 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.
  • reference number 206 corresponds to when the polished rod 130 begins its upward motion (e.g., upstroke) to begin to lift a column of fluid.
  • reference numbers 206 and 208 corresponds to when the increase in tension on the polished rod 130 is shown as the polished rod 130 is stretched and the fluid column is lifted.
  • Reference number 208 corresponds to when the pumping unit 100 is supporting the weight of the rod string 134 and the weight of the accelerating fluid column.
  • reference number 210 corresponds to when the polished rod 130 has reached its maximum upward displacement.
  • reference numbers 210 and 212 (at point 4), the fluid load is transferred from the rod string 134 to the tubing string 132, which causes the tension in the polished rod 130 to decrease.
  • Reference number 212 corresponds to when the load has substantially and/or completely transferred to the tubing string 132.
  • force waves reflect to the surface as the downstroke continues, which causes irregular loading on the polished rod 130 until the polished rod 130 reaches its lowest point and begins another stroke.
  • FIG. 3 shows an example pump dynamometer card 300 that can be generated in accordance with the teachings of this disclosure using data associated with the position of the polished rod 130 and the load on the polished rod 130.
  • the pump dynamometer card 300 is generated using data measured at the surface.
  • the x-axis 302 corresponds to the position of the downhole pump (e.g., 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 in FIG. 3.
  • the pressure difference across the pump 126 is proportional to the height (e.g., vertical extent) of the pump card 300.
  • the leakage through the pump 126 is directly proportional to the height of the pump card 300.
  • the measured data from a pumping unit stroke may be integrated to derive the area of the pump card 300.
  • the total area of a pump dynamometer card represents the amount of work (e.g., force acting over a distance) performed.
  • the area of the pump dynamometer card 300 represents the work performed by the pump 126.
  • the area of the card 300 can be used to determine the ideal production fluid volume V stro ke using Equation 1 below.
  • V str oke represents the ideal (e.g., no leakage) volume of fluid produced during a stroke (e.g., in )
  • Ape represents the area of a pump card (e.g., in-lbf) for the stroke
  • ⁇ represent the pressure across the piston 136 (e.g., the difference between the pump discharge pressure and the pump intake pressure) (e.g., in lbf/in ).
  • the relationship set forth in Equation 1 can only be used for a full pump card in a well that has anchored tubing.
  • the tubing 132 is anchored or secured to prevent the tubing 132 from moving and/or stretching during operation. If the tubing 132 is unanchored, the tubing 132 may move and/or stretch during operation. As a result, the area of the pump card 300 may be affected.
  • FIG. 4 shows an example ideal "full" pump dynamometer card 400 for a well (e.g., the well 102) with anchored tubing.
  • 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.
  • the shape of the card 400 is substantially rectangular. Even with the irregularities that may exist, the ideal area Apci for a pump card can be determined (e.g., approximated) using Equation 2 below.
  • Equation 2 A P ci represents the ideal area of the pump card (e.g., in/lbf), S max represents the maximum pump position (e.g., in), S m i n represents the minimum pump position (e.g., in), F max represents the maximum pump load (e.g., lbf) and F m i n represents the minimum pump load (e.g., lbf), which have been labeled in FIG. 4.
  • FIG. 5 shows an example ideal "full" pump dynamometer card 500 for a well (e.g., the well 102) with unanchored 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.
  • the pump card 500 is in the shape of a parallelogram. In particular, the slopes of the sides of the pump card 500 are less steep than the sides of the pump card 400, for example.
  • the slopes of the sides of the pump card 500 reflect the stretching and relaxation of the tubing string as the fluid load is transferred from the sucker rods 134 (e.g., on the upstroke) to the tubing 132 (e.g., on the downstroke).
  • the slopes of the sides of the pump card dF/ds may be determined using Equation 3 below.
  • Equation 3 dF/ds represents the slope of the sides of the pump card (e.g., lbf/in), E represents the modulus of elasticity of the tubing material (e.g., lbf/in ), A tu i ng represents the cross-sectional area of the tubing (e.g., in ) and L represents the length of the unanchored tubing (e.g., ft).
  • the pump card 500 is not a rectangle like the pump card 400 in FIG. 4.
  • Equation 2 cannot be applied to accurately measure the area of the pump card 500.
  • the ideal area A P ci for a pump card associated with unanchored tubing may be determined using Equation 4 below.
  • Equation 4 A TM represents the sum of the two triangular areas on the sides of the parallelogram (e.g., in-lbf), which can be determined using Equation 5 below.
  • Equation 5 The value for A TM determined using Equation 5 can be used in Equation 4 to determine the ideal area A P ci of the pump card.
  • FIG. 6 shows an example pump dynamometer card 600 for a well (e.g., the well 102) with anchored tubing that is about %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.
  • the pump card 600 When the pump 126 is not full, the pump card 600 retraces itself during the empty portion of the downstroke until the fluid is encountered by the piston 136. In other words, during a downstroke, the pump 126 should ideally be full of fluid. As such, the pressure of the fluid above and below the piston 136 is the same and, thus, the load on the pump 126 during the downstroke is typically zero. However, if the pump 126 is not full of fluid, then the piston 136 supports the column of fluid above the pump 126 as the piston 126 moves downward during the downstroke. Once the piston 136 encounters the fluid in the pump 126, the pressure above and below the piston 136 stabilizes and, thus, the load on the pump 126 moves to zero. As compared to FIG. 4, the pump card 400 in FIG. 4 includes a larger area than the pump card 600 in FIG. 6. The ideal area A P ci of the pump card 600 may be determined using Equation 6 below.
  • Equation 6 A TM represents the sum of the triangular areas (e.g., as calculated using Equation 5) and ⁇ represents a pump fillage factor (e.g., a fraction). Therefore, Equation 6 combines the pump fillage aspect with the tubing movement aspect to accurately determine the area of a pump card. For wells that are anchored, the length of the unanchored tubing L in Equation 5 is zero, which causes the value of A TM in Equation 6 to be zero. Equation 6 can be rearranged to solve for the pump fillage factor ⁇ , as shown in Equation 7 below.
  • Equation 7 A P c represents the actual integrated card area (e.g., in-lbf), which may be determined using the trapezoidal rule, for example. Equation 7 provides a means of determining (e.g., estimating) pump fillage factor ⁇ using known parameters (e.g., attributes) of a tubing string and a pump dynamometer card.
  • an example method or process for determining the pump fillage factor ⁇ may include computing a surface dynamometer card (e.g., the surface dynamometer card 200), computing (e.g., calculating) a pump dynamometer card (e.g., the pump dynamometer card 600, which may be based on a surface dynamometer card), analyzing the pump dynamometer card for maximum and minimum positions and maximum and minimum loads (S max , S m i n , F max , F m i n ), integrating the pump dynamometer card to determine the true or actual area A P c, calculating the triangular areas A TM using Equation 5 (if the tubing is unanchored) (L, E and A are known from the tubing configuration) and calculating the pump fillage factor ⁇ using Equation 7.
  • the pump fillage factor ⁇ may be determined for each stroke of the pumping unit 100. In some examples, the pump fillage factor ⁇ may be monitored and may be used to control the speed and/or on/off operations of the motor 110. For example, if the pump fillage factor ⁇ falls below a threshold or target value, the speed of the motor 110 may be decreased. As a result, there is relatively more time for the pump 126 to fill between strokes.
  • pump leakage occurs when there is a pressure difference across the pump 126. Therefore, any time a pump card shows a positive load on the pump 126, a pressure difference across the pump 126 is present. Additionally, the leakage rate is proportional to the pressure difference across the pump 126. Because a pressure difference across the pump is proportional to the load on the pump card, the leakage rate is proportional to the pump card load. The pump leaks on the upstroke because there is a pressure difference across the pump (e.g., as indicated by the load on the pump 126 during the upstroke).
  • the pump 126 may leak on the downstroke when fillage is less than 100%, because a pressure difference across the pump 126 exists when the pump 126 is less than 100% full.
  • the volume of fluid leakage LKG can be determined (e.g., approximated) using Equation 8 below.
  • Equation 8 LKG represents the volume of fluid leaked through a pump (e.g., in ) and CLKG represents a leakage proportionality constant (e.g., in /lbf).
  • the (2.0- ⁇ ) term in Equation 8 accounts for leakage on the downstroke. If the pump 126 is full (e.g., the volume of the bore 138 beneath the piston 136), then pump fillage factor ⁇ is 1.0, and the (2.0- ⁇ ) term becomes 1.0. However if the pump 126 is less than full such as %50, the pump fillage factor ⁇ is 0.5 and the (2.0- ⁇ ) term becomes 1.5, which reflects the leakage occurred during half of the downstroke.
  • net production for a pump stroke IP stroke can be determined using Equation 9 below.
  • Equations 1 and 8 may be combined into Equation 9 to produce Equation 10 below for the net production of a pump stroke IP stroke-
  • IPstroke Ap C ⁇ ( ⁇ ) - [CLKG (2-0 - ⁇ )] ⁇ Equation 10
  • Equation 10 the pressure difference ⁇ term in Equation 10 can be problematic to estimate from known or measured operational parameters.
  • the example methods and apparatus consider that the pressure across the pump ⁇ is proportional to the pump load.
  • a relationship for determining an instantaneous pressure measurement ⁇ may be determined using Equation 11 below.
  • ⁇ . JZLL Equation 1 1
  • Equation 1 1 ⁇ represents the instantaneous pressure across a pump (e.g., Ibf/in ), Fi represents instantaneous pump force (e.g., lbf) and A pump represents a cross-sectional area of the pump (e.g., in ).
  • F avg an average or mean force F avg on the pump 126 for a complete or full stroke (e.g., an upstroke and a downstroke)
  • the average force F avg can be determined used Equation 12 below.
  • Equation 12 [0044] Applying Equation 12 to Equation 1 1 leads to Equation 13 below.
  • Equation 13 AP avg represents the average pressure across the pump during times when leakage is occurring (e.g., Ibf/in ). Substituting Equation 13 into Equation 10 yields Equation 14 below, which provides an accurate method of inferring (e.g., estimating) the net production IP stro ke from a single stroke of a pumping unit.
  • IPstroke [ pump X (S m ax - S min ) X ⁇ ] - [A PC C LKG X (2.0 - ⁇ )] Equation 14 [0046] From Equation 14, production P 0 bserved for a series of strokes of the pumping unit can be estimated using Equation 15 below.
  • Equation 15 [0047]
  • P 0 bserved represents the total observed production during the series of strokes (e.g., in ) and ⁇ represents a summation of terms for all strokes during the
  • Equation 15 can be rearranged to solve for the leakage proportionality constant CLKG, which yields Equation 16 below.
  • a calibration process may be performed to derive the leakage proportionality constant CLKG-
  • a producing well may be coupled to a dedicated 2-phase or 3 -phase separator, which can measure liquid production from the well over a time period (e.g., 6 hours, 1 day, etc.) and/or for a certain number of strokes.
  • a separator 154 is illustrated in FIG. 1 that may separate oil from water and gas and determine a volume of produced oil.
  • the processor 152 may measure required parameters, calculate pump dynamometer cards (e.g., for each of the stroke) and perform calculations disclosed herein to determine a value for the ⁇ (S max — S mm ) X ⁇ term (e.g., a first summation term) and a value for the ⁇ A PC X (2.0— ⁇ ) term (e.g., a second summation term) based on the strokes of the pumping unit during the calibration period.
  • a value for the ⁇ (S max — S mm ) X ⁇ term e.g., a first summation term
  • a value for the ⁇ A PC X (2.0— ⁇ ) term e.g., a second summation term
  • the observed total liquid (oil and water) production P 0 bserved and the summation terms ⁇ (S m ax — S m j n ) X ⁇ and ⁇ A PC X (2.0— ⁇ ) may be used in Equation 16 to derive a value for the leakage proportionality constant C LKG -
  • the value for the leakage proportionality constant C LKG can then be used to infer or determine production for a single stroke (e.g., using
  • Equation 14 or for multiple strokes over a period of time (e.g., using Equation 15).
  • the inferred production of an individual stroke can be determined using Equation 14 and values available from a downhole dynamometer card.
  • the inferred production from individual strokes may be accumulated over a period of time (e.g., an hour, a day, a month, etc.), which may be determined using Equation 15.
  • Equation 13 above provides a means of determining or estimating the pressure difference ⁇ across the pump 126 using known attributes of the pump 126 and a pump dynamometer card.
  • Pump intake pressure PIP may be determined using Equation 17 below.
  • PIP represents the pump intake pressure (e.g., Ibf/in )
  • PDP represents pump discharge pressure (e.g., Ibf/in )
  • AP pump represents the pressure difference across the pump (which can be determined using Equation 13).
  • a number of methods can be used to determine (e.g., estimate) the pump discharge pressure PDP.
  • the fluid contained in the production tubing can be treated as a flowing or as a static vertical column of fluid. In some examples, because the fluid flow is cyclic (e.g., reciprocating rod pump systems only pump during upstroke) and the flow rates are relatively low, the friction pressure loss in the vertical column is often ignored. However, the density changes in the fluid column should be considered.
  • an example process may include starting at the surface with the surface discharge pressure (e.g., measured via a sensor), and incrementally calculating the pressure down the tubing string 132 (FIG. 1).
  • An example method or process may include (e.g., assuming fixed density within a section or discrete increment) (1) obtaining estimates of oil, water and gas production rates for a well; (2) obtaining or approximating pressure, volume and temperature (PVT) relationships of the liquid components over reasonable pressure and temperature ranges; (3) measuring or estimating surface discharge pressure and temperature; (4) using PVT characteristics, along with pressure and temperature estimates to calculate the density of the presumed oil, water and gas mixture at discharge pressure and temperature; (5) assuming the constant density over a discrete increment of depth or pressure; (6) calculating or estimating the depth, pressure and temperature at the bottom of the discrete increment; (7) determining if the pump depth has been reached, using the currently calculated pressure as the pump discharge pressure; and (8) if the pump depth has not been reached, returning to step 4.
  • the PVT relationships e
  • a processor may estimate pump discharge pressure, estimate pressure difference across the pump at the end of each stroke (e.g., using Equation 13) and apply Equation 17 to derive an estimated pump intake pressure.
  • the results of this example process may result in a relatively noisy pump intake pressure measurement (e.g., the pump intake pressure estimates may vary from stroke to stroke).
  • a damping function or low gain proportional-integral- derivative (PID) controller may be used, such that the processor can perform either on/off or variable speed control of the pumping system.
  • on/off control mode for example, the rod pump controller 146 may stop the pump 126 (e.g., stop the motor 110) and place the pumping unit 100 into temporary idle time when the estimated pump intake pressure is below the pump intake pressure threshold for a specified number of strokes.
  • the rod pump controller 146 may decrease pump speed when the estimated pump intake pressure is below the threshold and increase pump speed when the estimated pump intake pressure is above the threshold.
  • FIG. 1 While an example manner of implementing the apparatus 146 is illustrated in FIG. 1, one or more of the elements, processes and/or devices illustrated in FIG. 1 may be combined, divided, re-arranged, omitted, eliminated and/or implemented in any other way.
  • the example I/O device 148, the example memory 150, the example processor 152 and/or, more generally, the example apparatus 146 of FIG. 1 may be implemented by hardware, software, firmware and/or any combination of hardware, software and/or firmware.
  • the example I O device 148, the example memory 150 and/or the example processor 152 is/are hereby expressly defined to include a tangible computer readable storage device or storage disk such as a memory, a digital versatile disk (DVD), a compact disk (CD), a Blu- ray disk, etc. storing the software and/or firmware.
  • the example apparatus of FIG. 1 may include one or more elements, processes and/or devices in addition to, or instead of, those illustrated in FIG. 1, and/or may include more than one of any or all of the illustrated elements, processes and devices.
  • FIGS. 7, 8, 9 and 10A and 10B Flowcharts representative of example methods for implementing the apparatus 146 of FIG. 1 are shown in FIGS. 7, 8, 9 and 10A and 10B.
  • the methods of FIGS. 7, 8, 9 and 10A and 10B may be implemented machine readable instructions that comprise a program for execution by a processor such as the processor 1112 shown in the example processor platform 1100 discussed below in connection with FIG. 11.
  • the program may be embodied in software stored on a tangible computer readable storage medium such as a CD-ROM, a floppy disk, a hard drive, a digital versatile disk (DVD), a Blu-ray disk, or a memory associated with the processor 1112, but the entire program and/or parts thereof could alternatively be executed by a device other than the processor 1112 and/or embodied in firmware or dedicated hardware.
  • a tangible computer readable storage medium such as a CD-ROM, a floppy disk, a hard drive, a digital versatile disk (DVD), a Blu-ray disk, or a memory associated with the processor 1112, but the entire program and/or parts thereof could alternatively be executed by a device other than the processor 1112 and/or embodied in firmware or dedicated hardware.
  • FIGS. 7, 8, 9 and 10A and 10B many other methods of implementing the example apparatus 146 may alternatively be used. For example, the order of execution of the blocks may be changed, and/or some of the blocks described may be changed, eliminated,
  • FIGS. 7, 8, 9 and 10A and 10B may be implemented using coded instructions (e.g., computer and/or machine readable instructions) stored on a tangible computer readable storage medium such as a hard disk drive, a flash memory, a read-only memory (ROM), a compact disk (CD), a digital versatile disk (DVD), a cache, a random-access memory (RAM) and/or any other storage device or storage disk in which information is stored for any duration (e.g., for extended time periods, permanently, for brief instances, for temporarily buffering, and/or for caching of the information).
  • coded instructions e.g., computer and/or machine readable instructions
  • a tangible computer readable storage medium such as a hard disk drive, a flash memory, a read-only memory (ROM), a compact disk (CD), a digital versatile disk (DVD), a cache, a random-access memory (RAM) and/or any other storage device or storage disk in which information is stored for any duration (e.g., for extended time periods,
  • tangible computer readable storage medium is expressly defined to include any type of computer readable storage device and/or storage disk and to exclude propagating signals and to exclude transmission media.
  • tangible computer readable storage medium and “tangible machine readable storage medium” are used interchangeably. Additionally or alternatively, the example methods of FIGS.
  • 7, 8, 9 and 10A and 10B may be implemented using coded instructions (e.g., computer and/or machine readable instructions) stored on a non-transitory computer and/or machine readable medium such as a hard disk drive, a flash memory, a read-only memory, a compact disk, a digital versatile disk, a cache, a random-access memory and/or any other storage device or storage disk in which information is stored for any duration (e.g., for extended time periods, permanently, for brief instances, for temporarily buffering, and/or for caching of the information).
  • the term non-transitory computer readable medium is expressly defined to include any type of computer readable storage device and/or storage disk and to exclude propagating signals and to exclude transmission media.
  • the phrase "at least" is used as the transition term in a preamble of a claim, it is open-ended in the same manner as the term "comprising" is open ended.
  • FIG. 7 illustrates an example method 700 to calculate a pump fillage factor (e.g., fraction) for a pumping unit.
  • the example method 700 may be implemented by the apparatus 146 (e.g., using the processor 152) of FIG. 1, for example, to calculate a pump fillage factor for the pump 126.
  • the example method 700 includes computing a surface dynamometer card (block 702). As disclosed herein, a surface dynamometer card is based on measurements taken at the surface and displays polished rod load versus polished rod position.
  • FIG. 2 illustrates an example surface dynamometer card 200 that may be computed for the example pumping unit 100 of FIG. 1. The surface dynamometer card may be computed by the processor 152 of FIG. 1, for example.
  • the example method 700 includes computing a pump dynamometer card (block 704).
  • a pump dynamometer card may be computed using data collected for the surface dynamometer card and a mathematical computation process that models the flexibility of the sucker rod string.
  • FIGS. 3, 4, 5 and 6 illustrate example pump dynamometer cards that may be computed for the example pumping unit 100 of FIG. 1.
  • the pump dynamometer card may be computed by the processor 152 of FIG. 1, for example.
  • the example method 700 includes determining a maximum pump position S max , a minimum pump position S m i n , a maximum pump load F max and a minimum pump load F m i n from the pump dynamometer card (block 706).
  • the pump positions and loads may be determined by the processor 152 of FIG. 1, for example.
  • the example method 700 of FIG. 7 includes determining whether a tubing (e.g., tubing string) of the pumping unit is anchored (bock 708). As disclosed herein, if the tubing of a pumping unit is unanchored, the tubing may flex and stretch during operation. As a result, the force on the pump may be relaxed at times.
  • FIG. 4 shows an example pump dynamometer card 400 have a well having anchored tubing and a FIG. 5 shows an example pump dynamometer 500 of a well having unanchored tubing. If the tubing is anchored, the example method 700 includes calculating an ideal area A P ci of the pump dynamometer card for an anchored tubing (block 710).
  • the ideal area A P ci may be based on the maximum pump position S max , the minimum pump position S m m, the maximum pump load F max and the minimum pump load F mm .
  • the ideal area Apci may be calculated using Equation 2.
  • the example method 700 includes calculating an ideal area A P ci of the pump dynamometer card for unanchored tubing (block 712).
  • the ideal area may be based on the maximum pump position S max , the minimum pump position S m i n , the maximum pump load F max and the minimum pump load Fmin, the modulus of elasticity E of the tubing material, the cross-sectional area of the tubing A tubmg and the length L of the unanchored tubing.
  • the ideal area A P ci of a pump dynamometer card for unanchored tubing may be calculated using Equation 4.
  • the processor 152 of FIG. 1 may determine whether the tubing 136 is anchored or unanchored and may calculate the ideal area A P ci of the pump dynamometer card using the Equation 4.
  • the example method 700 includes calculating a true area A P c of the pump
  • the true area of the pump dynamometer card may be calculated using the trapezoidal rule, for example, or any other mathematical formula.
  • the true area A P c of a pump dynamometer card may be calculated by the processor 152 of FIG. 1, for example.
  • the example method 700 includes determining a pump fillage factor ⁇ based on the calculated ideal area A P ci of the pump dynamometer card and the true area A P c of the pump dynamometer card (block 716).
  • the pump fillage factor ⁇ may be determined using Equation 7.
  • the pump fillage factor ⁇ may be determined by the processor 152 of FIG. 1, for example.
  • the pump fillage factor ⁇ may be used to, among other things, determine intake pressure PIP of a pump and/or determine a leakage proportionality constant C LKG , which can then be used to infer production and/or control a pumping unit more efficiently.
  • the pump fillage factor can be used to control the speed and/or on/off operation of the pump.
  • the pump fillage factor can be monitored and when the pump fillage factor falls below a target value (e.g., for one stroke or a specified number of strokes), the pump can be stopped (or decreased in speed) and the well can be left in idle to allow the well casing to be filled by the producing formation. Therefore, when pumping is resumed (at the end of idle time), sufficient fluid may be present to fill the pump.
  • FIG. 8 illustrates an example method 800 to calculate or determine intake pressure of a pump.
  • the example method 800 may be implemented by the apparatus 146 (e.g., using the processor 152) of FIG. 1, for example, to determine intake pressure PIP of the pump 126.
  • the example method 800 includes determining a pump fillage factor ⁇ (block 802).
  • the pump fillage factor ⁇ may be determined using the example method 700 of FIG. 7, which may be implemented by the example apparatus 146 of FIG. 1.
  • the example method 800 includes calculating an average force F avg on a pump during a time period when leakage occurs (block 804).
  • the average force F avg may be based on, for example, an area Ape of a pump dynamometer card, a maximum position of the pump S max , a minimum position of the pump S m in and/or the pump fillage factor ⁇ .
  • the area A P c of a pump dynamometer card, the maximum position of the pump S max and the minimum position of the pump S m m are explained in connection with the method 700 of FIG. 7.
  • the average force F avg may be determined using Equation 12, which may be implemented by the processor 152 of FIG. 1, for example.
  • the example method 800 includes calculating an average pressure AP avg across the pump during times when leakage occurs (block 806).
  • the average pressure AP avg may be determined using Equation 13, which may be implemented by the processor 152 of FIG. 1, for example.
  • the average pressure AP avg is based on the true area A P c of the pump dynamometer card, the cross-sectional area A pump of the pump, the maximum position of the pump S max , the minimum position of the pump S m m and the pump fillage factor ⁇ .
  • the example method 800 includes obtaining estimates of oil, water and gas production rates for the well (block 808).
  • the estimates for the production rates may be obtained by the processor 152 of FIG. 1, for example.
  • the rates may be based on measurements from the separator 154. In other examples, the rates may be determined based on inferred production, such as determined in connection with the method in FIGS. 10A and 10B and disclosed in further detail herein.
  • the example method 800 of FIG. 8 includes obtaining or approximating pressure, volume and temperature relationships of the liquid components over pressure and
  • the example method 800 includes measuring or estimating surface discharge pressure and temperature (block 812).
  • the processor 152 of FIG. 1 may receive measurements via the I/O device 148 and determine a discharge pressure and temperature at the surface.
  • the example method 800 includes using pressure, volume and temperature characteristics, along with the pressure and temperature measurements/estimates, to calculate the density of the presumed oil/water/gas mixture at the discharge pressure and temperature (block 814).
  • the density may be calculated by the processor 152 of FIG. 1, for example.
  • the example method 800 includes assuming the constant density over a discrete increment of depth or pressure (block 816) and calculating the depth, pressure and temperature at the bottom of a discrete increment (block 818).
  • the discrete increment may be any increment (e.g., 1 mm).
  • the depth, pressure and temperature values may be calculated by the processor 152 of FIG. 1, for example.
  • the example method 800 includes determining when a pump depth has been reached (block 820). In other words, the method 800 includes determining whether the increment is the last or bottom most increment of the well. If not, the example method 800 includes using the pressure, volume and temperature characteristics to calculate the density and calculating the depth, pressure and temperature values at the bottom of the next discrete increment (blocks 814-818). This process may continue until the pump depth has been reached. If the pump depth has been reached, the method 800 includes using the currently calculated pressure as the pump discharged pressure (block 822) (e.g., the pressure value calculated at block 818) and calculating pump intake pressure based on the calculated pressure difference across the pump and the pump discharge pressure (block 824). The pump intake pressure may be calculated using Equation 17, which may be implemented by the processor 152 of FIG. 1, for example.
  • FIG. 9 illustrates a flowchart representative of an example method 900 that may be used to operate a pumping unit based on pump intake pressure.
  • the example method 900 may be implemented by the apparatus 146 (e.g., using processor 152) of FIG. 1, for example, to operate the pump 126 above or below a threshold intake pressure and/or pressure range.
  • the example method 900 includes determining pump intake pressure (block 902), which may be determined using the example method 800 of FIG. 8.
  • the example method 900 includes comparing the pump intake pressure to a pump intake pressure threshold (block 904).
  • the pump intake pressure may be a range (e.g., having an upper limit and a lower limit).
  • the pump intake pressure may be set by an operator.
  • the processor 152 of FIG. 1 may determine the intake pressure PIP of the pump 126 and compare the intake pressure PIP to a pump intake pressure threshold.
  • the example method 900 includes determining whether the pump intake pressure is within the pump intake pressure threshold (block 906). For example, the pump intake pressure may be higher than an allowed or threshold pump intake pressure. If the pump intake pressure is not within the pump intake pressure threshold, the example method 900 includes starting or stopping the pump and/or changing the speed of the pump (block 908). For example, the apparatus 146 of FIG. 1 may be used to control the motor 110 to increase or decrease the speed of the motor 110. As disclosed herein, in some examples it may be desired for the pump to operate above a set intake pressure threshold, which may enable lighter hydrocarbons to remain in liquid phase, for example.
  • the example method 900 includes determining whether monitoring of the well is to continue (block 910). If monitoring is to continue, the example method 900 may repeat. Otherwise, the example method 900 may end.
  • FIGS. 10A and 10B illustrate a flowchart representative of an example method 1000 that may be used to infer production of an oil well.
  • the example method 1000 may be implemented by the apparatus 146 (e.g., using the processor 152) of FIG. 1, for example, to infer production of the well 102 by the pumping unit 100.
  • the example method 1000 includes obtaining pump parameters or attributes such as a diameter of the pump, a cross- sectional area A pump of the pump, the modulus of elasticity E of the tubing material and/or the length L of any unanchored tubing (block 1002).
  • the parameters or attributes may be obtained by the processor 152 of FIG. 1, for example.
  • the process of directly measuring liquid production from a well e.g., the well 102 of FIG. 1 for a first
  • the example method 1000 includes determining if the pumping unit has completed a stroke (block 1008).
  • the processor 152 may determine if the pumping unit 100 has completed a stroke.
  • the processor 152 determines that the pumping unit 100 completes a stroke based on feedback received from a sensor adjacent the crank arm 116. If a stroke of the pumping unit has not been completed, the method continues to directly measure the liquid produced from the well (block 1006).
  • the example method 1000 includes computing a pump dynamometer card based on, for example, a determined surface dynamometer card and/or data collected for the surface dynamometer card (block 1010).
  • the pump dynamometer card may be computed by the processor 152 of FIG. 1, for example.
  • the example method 1000 includes determining a maximum pump position S max , a minimum pump position S m i n , a maximum pump load F max and a minimum pump load F m i n from the pump dynamometer card (block 1012).
  • the pump positions and loads may be determined by the example processor 152 of FIG. 1, for example.
  • the example method 1000 includes determining an area A P c of the pump dynamometer card (block 1014). For example, the processor 152 may determine the area A P c of a pump card using the trapezoidal rule.
  • the example method 1000 includes determining a pump fillage factor ⁇ (block 1016).
  • the pump fillage factor ⁇ may be determined using the example method 700 of FIG. 7.
  • the example method 1000 includes calculating a first summation value and a second summation value (block 1018) for the pump dynamometer cards of the stroke(s) that have occurred during the first predetermined time period and/or the first predetermined number of strokes.
  • the first summation value may be calculated using ⁇ (S max — S m j n ) X ⁇ for the stroke(s) occurred during the first predetermined time period
  • the second summation value may be calculated using ⁇ A PC X (2.0— ⁇ ) for the stroke(s) occurred during the first predetermined time period.
  • the first and second summation values may be determined by the processor 152 of FIG. 1, for example.
  • the example method 1000 includes determining whether the first predetermined time period has elapsed and/or if the first predetermined number of strokes of the pumping unit has occurred (block 1020). For example, the processor 152 of FIG. 1 may determine if the first predetermined time period has elapsed and/or the first predetermined number of strokes has occurred. If the first predetermined time period has not elapsed and/or if the
  • the example method 1000 includes determining total liquid production P 0 bserved during the first predetermined time period and/or for the first
  • the example method 1000 includes determining a leakage proportionality constant C LKG (block 1024). The leakage
  • proportionality constant C LKG may be based on the pump parameters (e.g., obtained at block 1002), the total liquid production P 0 bserved during the first predetermined time period and/or during the first predetermined number of strokes (e.g., obtained at block 1022) and/or the first summation value and the second summation value (e.g., obtained at block 1020).
  • the leakage proportionality constant C LKG may be determined using Equation 16, which may be implemented by the example processor 152 of FIG. 1.
  • the example method 1000 includes determining (e.g., inferring) production of the pumping unit during normal operation and/or while the pumping unit is continuously operating for a second predetermined time period (block 1026).
  • the second predetermined time period may be, for example, an hour, a day, a week, a month, etc.
  • the example method 1000 includes determining whether the pumping unit has completed a stroke (block 1028) (e.g., a complete cycle including an upstroke and a downstroke). If the pumping unit has not completed a stroke, the method 1000 iteratively determines if a stroke has completed. If the pumping has completed a stroke (e.g., determined by the processor 152), the example method 1000 includes computing a pump dynamometer card (block 1030). The pump dynamometer card may be based on, for example, a determined surface
  • the pump dynamometer card may be computed by the processor 152 of FIG. 1, for example.
  • the example method 1000 includes determining a maximum pump position S max , a minimum pump position S m i n , a maximum pump load F max and a minimum pump load F m i n from the pump dynamometer card (block 1032).
  • the pump positions and loads may be determined by the example processor 152 of FIG. 1, for example.
  • the example method 1000 includes determining an area A P c of the pump dynamometer card (block 1034). For example, the processor 152 may determine the area Apc of a pump card using the trapezoidal rule.
  • the example method 1000 includes determining a pump fillage factor ⁇ (block 1036).
  • the pump fillage factor ⁇ may be determined using the example method 700 of FIG. 7.
  • the processor 152 may determine the pump fillage factor ⁇ using Equation 7.
  • the example method 1000 includes determining inferred production of the stroke of the pumping unit (block 1038).
  • the production of the pumping unit may be based on the pump parameters (e.g., obtained at block 1002), the pump fillage factor ⁇ (e.g., obtained at block 1036) and/or the leakage proportionality constant C LKG (e- -, obtained block 1024).
  • the production IP str oke may be determined using Equation 14, which may be implemented by the processor 152 of FIG. 1.
  • the example method 1000 includes
  • the example method 1000 determines whether the second predetermined time period has elapsed and/or the second predetermined number of strokes has occurred (block 1040). If the second predetermined time period has not elapsed and/or the second predetermined number of strokes has not occurred, the example method 1000 continues to block 1028 where the method 1000 continues to determine whether the pumping unit has completed another stroke. If the second predetermined time period has elapsed and/or the second predetermined number of strokes has occurred, the example method 1000 includes summing the production from the stroke(s) (block 1042). The total production P 0 bserved of all the stroke(s) may be determined using Equation 15, for example. The total production P 0 bserved may be determined by the processor 152 of FIG. 1, for example. The example method 1000 may repeat itself as desired.
  • the example method 1000 may end.
  • FIG. 11 is a block diagram of an example processor platform 1100 capable of executing instructions to implement the methods of FIGS. 7, 8, 9 and 10A and 10B and/or to implement the apparatus 146 of FIG. 1.
  • the processor platform 1100 can be, for example, a server, a personal computer, a mobile device (e.g., a cell phone, a smart phone, a tablet such as an iPadTM), a personal digital assistant (PDA), an Internet appliance or any other type of computing device.
  • a mobile device e.g., a cell phone, a smart phone, a tablet such as an iPadTM
  • PDA personal digital assistant
  • Internet appliance any other type of computing device.
  • the processor platform 1100 of the illustrated example includes a processor 1112.
  • the processor 1112 of the illustrated example is hardware.
  • the processor 1112 can be implemented by one or more integrated circuits, logic circuits, microprocessors or controllers from any desired family or manufacturer.
  • the processor 1112 of the illustrated example includes a local memory 1113 (e.g., a cache).
  • the processor 1112 of the illustrated example is in communication with a main memory including a volatile memory 1114 and a non-volatile memory 1116 via a bus 1118.
  • the volatile memory 1114 may be implemented by Synchronous Dynamic Random Access Memory (SDRAM), Dynamic Random Access Memory (DRAM), RAMBUS Dynamic Random Access Memory (RDRAM) and/or any other type of random access memory device.
  • the non-volatile memory 1116 may be implemented by flash memory and/or any other desired type of memory device. Access to the main memory 1114, 1116 is controlled by a memory controller.
  • the processor platform 1100 of the illustrated example also includes an interface circuit 1120.
  • the interface circuit 1120 may be implemented by any type of interface standard, such as an Ethernet interface, a universal serial bus (USB), and/or a PCI express interface.
  • one or more input devices 1122 are connected to the interface circuit 1120.
  • the input device(s) 1122 permit(s) a user to enter data and commands into the processor 1112.
  • the input device(s) can be implemented by, for example, an audio sensor, a microphone, a camera (still or video), a keyboard, a button, a mouse, a touchscreen, a track-pad, a trackball, isopoint and/or a voice recognition system.
  • One or more output devices 1124 are also connected to the interface circuit 1120 of the illustrated example.
  • the output devices 1124 can be implemented, for example, by display devices (e.g., a light emitting diode (LED), an organic light emitting diode (OLED), a liquid crystal display, a cathode ray tube display (CRT), a touchscreen, a tactile output device, a printer and/or speakers).
  • the interface circuit 1120 of the illustrated example thus, typically includes a graphics driver card, a graphics driver chip or a graphics driver processor.
  • the interface circuit 1120 of the illustrated example also includes a communication device such as a transmitter, a receiver, a transceiver, a modem and/or network interface card to facilitate exchange of data with external machines (e.g., computing devices of any kind) via a network 1126 (e.g., an Ethernet connection, a digital subscriber line (DSL), a telephone line, coaxial cable, a cellular telephone system, etc.).
  • a communication device such as a transmitter, a receiver, a transceiver, a modem and/or network interface card to facilitate exchange of data with external machines (e.g., computing devices of any kind) via a network 1126 (e.g., an Ethernet connection, a digital subscriber line (DSL), a telephone line, coaxial cable, a cellular telephone system, etc.).
  • DSL digital subscriber line
  • the processor platform 1100 of the illustrated example also includes one or more mass storage devices 1128 for storing software and/or data.
  • mass storage devices 1128 include floppy disk drives, hard drive disks, compact disk drives, Blu-ray disk drives, RAID systems, and digital versatile disk (DVD) drives.
  • Coded instructions 1132 to implement the methods of FIGS. 7, 8, 9 and 10A and 10B may be stored in the mass storage device 1128, in the volatile memory 1114, in the nonvolatile memory 1116, and/or on a removable tangible computer readable storage medium such as a CD or DVD.
  • 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.
  • the estimated production from each stroke can be summed over a period of time (e.g., hourly, daily, monthly, etc.) to infer, estimate and/or determine production estimate for the pumping unit.
  • a rod pump controller does not calculate the downhole pump card.
  • the examples disclosed herein can be incorporated on a computing platform of moderate to low computational power. Using the examples disclosed herein, there is no need to analyze the downhole pump card to identify the net liquid stroke, the fluid load or other such parameters from the downhole card.
  • a leakage test is not performed because the leakage proportionality constant is determined using calculations associated with a well test.
  • the examples disclosed herein can be implemented in a field controller.
  • An example method disclosed herein includes measuring an amount of liquid produced from a well by a pumping unit during a predetermined time period and determining first areas of first pump cards during the predetermined time period.
  • the example method includes summing the first areas and, based on the amount of liquid produced and the summed first areas, determining a leakage proportionality constant of a downhole pump of the pumping unit.
  • the method also includes, while continuously operating the pumping unit, determining a second area of a second pump card. In some examples, the method also includes determining a net fluid produced during a stroke of the pumping unit based on the leakage proportionality constant and the second area. In some examples, measuring the amount of liquid produced includes measuring the liquid produced at separator conditions using a well test separator.
  • determining the first areas of first pump cards during the predetermined time period includes using a rod pump controller to determine the first areas.
  • the method also includes, while continuously operating the pumping unit over a second predetermined time period, determining second areas of second pump cards.
  • the method also includes determining a net fluid produced during the second predetermined time period based on the proportionality constant and the second areas.
  • the leakage proportionality constant is determined further based on a pressure difference across the downhole pump of the pumping unit.
  • An example apparatus disclosed herein includes a housing for use with a pumping unit and a processor positioned in the housing.
  • the processor is to determine first areas of first pump cards during a predetermined time period, sum the first areas and, based on an amount of liquid produced by a downhole pump of the pumping unit during the
  • the processor while continuously operating the pumping unit, the processor is to determine a second area of a second pump card. In some examples, the processor is to determine a net fluid produced during a stroke of the pumping unit based on the leakage proportionality constant and the second area. In some examples, the apparatus includes a rod pump controller. In some examples, while continuously operating the pumping unit over a second predetermined time period, the processor is to determine second areas of second pump cards. In some examples, the processor is to determine a net fluid produced during the second predetermined time period based on the proportionality constant and the second areas. In some examples, the processor is to determine the leakage proportionality constant further based on a pressure difference across the downhole pump of the pumping unit.
  • Another example method disclosed herein includes measuring a first amount of liquid produced from a well by a pump during a first stroke of the pump, computing a first pump card based on the first stroke, determining a first area of the first pump card and determining a leakage proportionality constant of the pump based on the first amount of liquid produced and the first area.
  • the example method also includes computing a second pump card based on a second stroke of the pump, determining a second area of the second pump card and determining a second amount of liquid produced by the pump during the second stroke based on the leakage proportionality constant and the second area.
  • the method includes determining a first pump fillage factor for the pump during the first stroke.
  • the leakage proportionality constant is further based on the first pump fillage factor.
  • the method includes determining an ideal area of the first pump card.
  • the first pump fillage factor is based on a ratio of the determined first area of the first pump card and the ideal area of the first pump card.
  • the method includes determining whether a tubing of the pump is anchored. In some examples, if the tubing is not anchored, the ideal area of the first pump card is based on a modulus of elasticity of a material of the tubing, a cross-sectional area of the pump and a length of the unanchored tubing.
  • method includes determining a second pump fillage factor for the pump during the second stroke.
  • the second amount of liquid produced is further based on the second pump fillage factor.
  • the method includes determining a pressure difference across the pump during the first stroke based on the first pump fillage factor.
  • the leakage proportionality constant is determined further based on the pressure difference across the pump.
  • the first amount of liquid produced is measured using a separator.
  • the method includes computing a third pump card based on a third stroke of the pump, determining a third area of the third pump card, determining a third amount of liquid produced by the pump during the third stroke based on the leakage proportionality constant and the third area and summing the second amount and third amount to determine a net fluid produced by the pump during the second and third strokes.
  • Another example apparatus disclosed herein includes a housing to be used with a pumping unit having a downhole pump and a processor disposed in the housing.
  • the processor of the example apparatus is to determine a first area of a first pump card based on a first stroke of the pump, determine a leakage proportionality constant of the pump based on a first amount of liquid produced by the pump during the first stroke and the first area, determine a second area of a second pump card based on a second stroke of the pump and determine a second amount of liquid produced by the pump during the second stroke based on the leakage proportionality constant and the second area.
  • the apparatus includes a separator.
  • the separator is to measure the first amount of liquid produced by the pump during the first stroke.
  • the processor is to determine a first pump fillage factor for the pump during for the first stroke.
  • the leakage proportionality constant is further based on the first pump fillage factor.
  • the processor is to determine a second pump fillage factor for the pump during the second stroke.
  • the second amount of fluid produced is further based on the second pump fillage factor.
  • the processor is to determine an intake pressure of the pump during the second stroke based on the second pump fillage factor.
  • the apparatus includes a motor to drive the pump. In such an example, the processor is to control a speed of the motor based on the intake pressure of the pump.
  • Disclosed herein is an example tangible machine readable storage device having instructions that, when executed, cause a machine to at least compute a first pump card based on a first stroke of a downhole pump, determine a first area of the first pump card and determine a leakage proportionality constant of the pump based on a first amount of liquid produced by the pump during the first stroke and the first area.
  • the instructions are also to cause the machine to compute a second pump card based on a second stroke of the pump and determine a second amount of fluid produced by the pump during the second stroke based on the leakage proportionality constant and the second area.
  • the instructions, when executed, further cause the machine to determine a first pump fillage factor for the pump during the first stroke. In such an example, the leakage proportionality constant is further based on the first pump fillage factor. In some examples, the instructions, when executed, further cause the machine to determine a second pump fillage factor for the pump during the second stroke. In such an example, the second amount of liquid produced is further based on the second pump fillage factor. In some examples, the instructions, when executed, further cause the machine to determine an ideal area of the second pump card. In such an example, the second pump fillage factor is based on a ratio of the determined second area of the second pump card and the ideal area of the second pump card. In some such examples, the instructions, when executed, further cause the machine to determine a pressure difference across the pump during the second stroke based on the second pump fillage factor.

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  • Geophysics (AREA)
  • Control Of Positive-Displacement Pumps (AREA)
  • Examining Or Testing Airtightness (AREA)
  • Reciprocating Pumps (AREA)
  • Financial Or Insurance-Related Operations Such As Payment And Settlement (AREA)
  • Jet Pumps And Other Pumps (AREA)
  • Details And Applications Of Rotary Liquid Pumps (AREA)
  • Structures Of Non-Positive Displacement Pumps (AREA)

Abstract

L'invention concerne des procédés et un appareil permettant de déterminer la production d'une pompe de fond de trou. Un procédé donné à titre d'exemple consiste à mesurer une première quantité de liquide produit à partir d'un puits par une pompe pendant une première course de la pompe, à calculer une première carte de pompe sur la base de la première course, à déterminer une première zone de la première carte de pompe et à déterminer une constante de proportionnalité de fuite de la pompe sur la base de la première quantité de liquide produit et de la première zone. Le procédé donné à titre d'exemple consiste également à calculer une seconde carte de pompe en se basant sur une seconde course de la pompe, à déterminer une seconde zone de la seconde carte de pompe et à déterminer une seconde quantité de liquide produit par la pompe pendant la seconde course en se basant sur la constante de proportionnalité de fuite et la seconde zone.
EP16738945.1A 2015-06-29 2016-06-29 Procédés et appareil de détermination de la production de pompes de fond de trou Active EP3314087B1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US14/753,335 US10352149B2 (en) 2014-03-25 2015-06-29 Methods and apparatus to determine production of downhole pumps
PCT/US2016/039939 WO2017004110A1 (fr) 2015-06-29 2016-06-29 Procédés et appareil de détermination de la production de pompes de fond de trou

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EP3314087A1 true EP3314087A1 (fr) 2018-05-02
EP3314087B1 EP3314087B1 (fr) 2019-08-07

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JP (1) JP6875053B2 (fr)
CN (2) CN106326630B (fr)
AR (1) AR105175A1 (fr)
BR (1) BR112017028098B1 (fr)
CA (1) CA2990440A1 (fr)
MX (1) MX2017017007A (fr)
RU (1) RU2726697C2 (fr)
SA (1) SA517390595B1 (fr)
WO (1) WO2017004110A1 (fr)

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CN106326630B (zh) * 2015-06-29 2022-01-18 布里斯托公司商用名远程自动化解决方案 用于确定井下泵的产量的方法和装置
CN108729902B (zh) * 2018-05-03 2021-09-10 西安永瑞自动化有限公司 抽油机在线故障诊断系统及其诊断方法
CN113445994B (zh) * 2021-07-06 2022-06-07 燕山大学 基于连续系统振型叠加法的抽油机井泵功图转化方法
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CN116838323B (zh) * 2023-08-04 2023-12-05 大庆石油管理局有限公司 一种塔架式抽油机安全防护方法

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CN206757617U (zh) 2017-12-15
AR105175A1 (es) 2017-09-13
CN106326630B (zh) 2022-01-18
RU2018101976A (ru) 2019-07-30
EP3314087B1 (fr) 2019-08-07
BR112017028098A2 (pt) 2018-08-28
JP6875053B2 (ja) 2021-05-19
RU2018101976A3 (fr) 2019-12-24
BR112017028098B1 (pt) 2022-10-04
SA517390595B1 (ar) 2023-01-04
JP2018519446A (ja) 2018-07-19
CN106326630A (zh) 2017-01-11
RU2726697C2 (ru) 2020-07-15
WO2017004110A1 (fr) 2017-01-05
MX2017017007A (es) 2018-04-30
CA2990440A1 (fr) 2017-01-05

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