WO2016043866A1

WO2016043866A1 - Centrifugal pump degradation monitoring without flow rate measurement

Info

Publication number: WO2016043866A1
Application number: PCT/US2015/044241
Authority: WO
Inventors: Lawrence Camilleri
Original assignee: Schlumberger Canada Limited; Services Petroliers Schlumberger; Schlumberger Holdings Limited; Schlumberger Technology B.V.; Prad Research And Development Limited; Schlumberger Technology Corporation
Priority date: 2014-09-15
Filing date: 2015-08-07
Publication date: 2016-03-24

Abstract

A method for monitoring a pump. The method includes determining a measured power absorbed by the pump, generating a performance indicator by comparing the measured power to a reference power for the pump, populating a log of performance indicators, and comparing a performance indicator to prior performance indicators in the log to identify changes in the performance indicator as a function of time.

Description

CENTRIFUGAL PUMP DEGRADATION MONITORING

WITHOUT FLOW RATE MEASUREMENT

Inventor(s): Lawrence Anthony Patrick Camilleri

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] The present application claims the benefit of U.S. Provisional Application No. 62/050,698 filed September 15, 2014, and entitled "Centrifugal Pump Degradation Monitoring Without Flow Rate Measurement" which is incorporated herein in its entirety for all purposes.

TECHNICAL FIELD

[0002] This disclosure relates generally to the field of pump monitoring. Specifically, the disclosure relates to prognostics and health management methods for pumps without the need for measuring or knowing flow rate.

BACKGROUND

[0003] Traditional methods for the determination of pump performance degradation are based on measuring flow rate and/or pump intake and discharge temperatures. Eliminating the need for flow rate measurements is desirable because in many instances it is either difficult or impossible to measure flow rate with sufficient accuracy.

SUMMARY

[0004] In general, a method is provided for use with various types of centrifugal pumps, which may entail identifying pump degradation and the cause of the degradation without flow rate data. A method for monitoring a pump can include determining a measured power absorbed by the pump, generating a performance indicator by comparing the measured power to a reference power for the pump, populating a log of performance indicators, and comparing a performance indicator to prior performance indicators in the log to identify changes in the performance indicator as a function of time. A system for monitoring various types of centrifugal pumps can include a pump that is configured to receive power from an electric motor or a prime mover, and a processor receiving data related to the pump's performance. The processor is configured to receive data related to a voltage from the power source, a current from the power source, and a frequency from the power source and based on the received data, generate an indication of measured power absorbed by the pump. The processor is also configured to generate a performance indicator based on a comparison of the measured power to a reference power absorbed by the pump. A non-transitory computer readable medium can, upon execution by a processor, cause the processor to receive data related to a voltage, a current, and a frequency from a power source and based on the received data, generate an indication of measured power absorbed by the pump. The processor is further caused to generate a performance indicator based on a comparison of the measured power to a reference power absorbed by the pump and create a log of performance indicators.

[0005] However, many modifications are possible without materially departing from the techniques of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.

BRIEF DESCRIPTION OF THE FIGURES

[0006] Certain embodiments of the disclosure will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements. It should be understood, however, that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein, and:

[0007] Figure 1A is a system diagram of an oil completion produced with an ESP in accordance with various embodiments of the present disclosure;

[0008] Figure IB shows a traditional set of centrifugal pump curves, presenting head and efficiency plotted as a function of flow rate;

[0009] Figure 2 presents the data of Figure 1 plotted independently of flow rate in accordance with various embodiments of the present disclosure, and specifically shows the ratio of differential pressure (DP) to absorbed power (P) plotted versus DP;

[0010] Figure 3 presents plots of DP/P versus DP in accordance with various embodiments of the present disclosure, and specifically for a range of pumps illustrating that each pump's stage geometry results in a unique curve;

[0011] Figures 4A and 4B show the effect of frequency on various pump curves in accordance with various embodiments of the present disclosure;

[0012] Figure 4C shows how the curves in Figure 4B can be collapsed to a single curve applying affinity laws for frequency in accordance with various embodiments of the present disclosure;

[0013] Figures 5A and 5B demonstrate the effect of specific gravity on various pump curves in accordance with various embodiments of the present disclosure; [0014] Figure 6 presents plots of P versus DP for a range of pumps in accordance with various embodiments of the present disclosure, illustrating that each pump's stage geometry has a unique curve;

[0015] Figures 7A and 7B illustrate the effect of head degradation on various pump curves without any efficiency or flow degradation in accordance with various embodiments of the present disclosure;

[0016] Figures 8A and 8B illustrate the effect of efficiency degradation on various pump curves without any head or flow degradation in accordance with various embodiments of the present disclosure;

[0017] Figures 9A and 9B illustrate the effect of flow rate degradation on various pump curves without any head or efficiency degradation in accordance with various embodiments of the present disclosure;

[0018] Figure 10 shows a process flow for identifying and measuring pump degradation without measuring or knowing flow rate, according to various embodiments of the present disclosure;

[0019] Figure 11 shows an example well installation identifying the data collected in accordance with various embodiments of the present disclosure;

[0020] Figure 12 is a chart showing the ratio of change in SG and measured water cut as a function of time in accordance with an embodiment of the disclosure;

[0021] Figure 13 is a chart showing a key performance indicator (KPI) as a function of time;

[0022] Figure 14 presents a diagnostic plot and best fit curves for DP/P versus DP-corrected in accordance with various examples of the present disclosure;

[0023] Figure 15 demonstrates an expected effect of degradation due to free gas and wear in accordance with various examples of the present disclosure;

[0024] Figure 16 provides a diagnostic plot of the expected effect of degradation due to viscosity in accordance with various examples of the present disclosure;

[0025] Figure 17 provides an example of a relationship between head degradation and efficiency degradation caused by viscous fluids in accordance with various examples of the present disclosure;

[0026] Figure 18 provides an example of DP/P versus DP after power calibration in accordance with various examples of the present disclosure; and

[0027] Figure 19 provides an example showing a KPI after power calibration as a function of time in accordance with various examples of the present disclosure. DETAILED DESCRIPTION

[0028] In the following description, numerous details are set forth to provide an understanding of the present disclosure. However, it will be understood by those skilled in the art that the present disclosure may be practiced without many of these details and that numerous variations or modifications from the described embodiments are possible.

[0029] As used herein, the following nomenclature is used:

[0030] The present disclosure generally relates to a methodology for use in centrifugal pumping applications, including, electric submersible pump (ESP) applications or other pumping applications. It should be noted from the outset that while reference may be made to particular embodiments directed to monitoring an ESP performance, aspects of the present disclosure are also applicable to other centrifugal pumping operations and the scope of the present disclosure should not be limited to only those embodiments in which an ESP is monitored. The present disclosure describes a method that may be readily implemented on wells with centrifugal pumps equipped with gauges to measure both intake and discharge pressure. The methodology makes use of a key performance indicator (KPI) as an indicator of pump performance change, which is typically degradation in pump performance, although in some cases the change may represent an improvement in pump performance. The KPI may be used as an alarm for degradation and/or as an alert to recalibrate the pump model, as discussed in further detail below.

[0031] Figure 1A depicts one example of a completion 10 within a well bore 12. The completion 10 incorporates a centrifugal pump, e.g., an electric submersible pump (ESP) 24. There are many examples of possible well completion architectures which may incorporate various other downhole tools such as packers, by-pass tubing and ESP encapsulation, among others. The presently disclosed systems and methods are independent of the completion architecture used in the specific application, and are more generally directed to monitoring performance of a centrifugal pump. While the disclosure of the system and method herein is focused on hydrocarbon wells, it is understood that embodiments may be used for any type of liquid being pumped with an ESP or, more generally, any centrifugal pump. Non-limiting examples include: hydrocarbons from an oil well, water from a water well, water from a geothermal well, water from a gas well, or hydrocarbons from a sump. In the case of an oil well, an ESP 24 may be deployed in the completion 10 in order to improve production of hydrocarbons.

[0032] The ESP 24 includes a motor 26 and a pump 30. The motor 26 operates to drive the pump 30 in order to increase hydrocarbon production to the surface. The ESP 24 further includes an intake pressure gauge 32, which may be an integral part of ESP 24 or a separate device. The intake pressure gauge 32 may be a part of a multisensory unit that includes a variety of sensors such as may be recognized by one of ordinary skill in the art. The intake pressure gauge 32 mea sures the pressure upstream of the ESP 24. The ESP 24 further includes a discharge pressure gauge 34, which may be an integral part of the ESP 24, or may be a separate device. The discharge pressure gauge 34 measures the pressure downstream of the ESP 24, While this description has been of pressure gauges that are permanent components of the pipe string with the ESP, it is to be understood that in other embodiments, a memory pressure gauge may be used. With a memory pressure gauge, the pressure gauge is installed temporarily within the completion and the gauge records the measured pressure to a computer readable medium, which is either within the gauge or at the surface. After a time interval, for example, one month, the memory pressure gauge is removed from the well and the measured pressure data is uploaded to a computer system for processing. In some embodiments, temperature sensors (not depicted) are included in the ESP 24 or as part of a multisensory unit. The temperature sensors measure the temperature of the hydrocarbons at an intake of the ESP and also measure the temperature of the motor 26. Various other embodiments may likewise include other downhole sensors to detect various parameters, and the scope of the present disclosure should not be limited to any particular sensor type.

[0033] The motor 26 of the ESP 24 receives electrical energy via switchgear 36 which may be located at the surface, outside of the well completion. The switchgear 36 controls power to the motor 26, which is provided by a generator or utility connection as recognized by one of ordinary skill. In the embodiment depicted, the switchgear is a variable speed drive (VSD) 36; however, any type of switchgear may be used. The VSD 36 delivers electric energy to the ESP 24 through an electrical conduit 38. The VSD 36 may be connected to, or include, a variety of sensors for monitoring conditions of the VSD 36. In one embodiment, the VSD 36 includes a voltmeter 42, an ammeter 44, and a frequency transducer 46. These three devices measure operational characteristics of the VSD 36, for instance, voltage, current, and frequency. In some embodiments, these devices are also used to determine the power factor, motor output torque, shaft speed, slip, or voltage imbalance. These sensors can monitor the operational characteristics of the VSD 36 at any refresh rate from, e.g., intervals of fractions of seconds to months or more. In embodiments where the VSD 36 does not include its own voltmeter, ammeter and frequency transducers, separate surface transducers 42, 44, and 46 may be used. In a still further embodiment, one or more of the values of voltage, and frequency are provided to the VSD 36 by a technician as operational inputs. The VSD then operates to provide electrical energy at these characteristics.

[0034] The monitored operational data may be sent from the VSD 36 to an integrated surface panel (ISP) 48 for further processing. The ISP 48 may also be communicatively connected to the intake pressure gauge 32 and to the discharge pressure gauge 34. The ISP receives the monitored intake pressure from the intake pressure gauge 32 and the discharge pressure from the discharge pressure gauge 34. While in some embodiments, the ISP 48 may receive signals (e.g., intake pressure, discharge pressure, voltage, current, and frequency) in real time or near-real time; in other embodiments the processor may receive the data from memory gauges that incorporate a buffer or other time delay. Furthermore, the data refresh rate can vary widely from intervals of seconds to months or more. In one embodiment, a measured value is received by the ISP 48 periodically, e.g., daily, hourly, or each minute; however, such refresh rates are not intended to be limiting on the scope of this disclosure.

[0035] The ISP 48 may include a processor 50 that is communicatively connected to a computer readable medium 52 programmed with computer readable code that upon execution by the processor 50 causes the processor 50 to perfonn the functions as disclosed in further detail herein. The ISP 48 may further comprise a computer readable medium that operates as a database 54. The processor 50 stores the data received and calculated by the processor 50 in the database 54. The processor 50 may control a graphical display 55 (e.g., a visual display device), for example, to present a graph of the fog of calculated values and, for example, a graph that presents a qualitative analysis of a flow rate trend of the flow rate through an electric submersible pump (ESP).

[0036] ISP 48 may transmit the recorded and processed data to one or more remote locations. The transmission of the recorded and processed data, may be performed using wired or wireless communication platforms such as local intranet communication, radio frequency (RF) transmission, or satellite transmission. However, in some situations, there is no data transmission and the user downloads the data manually from the ISP memory to portable storage for entry into the processor. In some embodiments, the processor can be located at the well site while in others the processor is located remotely.

[0037] It is to be unders tood by those of ordinary skill in the art that the communication and processing components of this system may be arranged in a wide range of configurations while being within the scope of the present disclosure. In one such configuration, the processor 50 is not integrated with the ISP 48, but is connected locally by a wired or wireless data connection. In such an embodiment, the processor 50 may be a laptop computer (not depicted) used by a well operator to establish a data connection with the ISP 48. The laptop computer may include the computer readable mediums 52 and 54. In another configuration, the ISP 48 transmits the measured values to a remote computer or server through a wired, wireless, or satellite data connection. Therefore, the processor 50 and computer readable mediums 52 and 54 would be located remotely from the ISP 48. In such embodiments, the ISP 48 performs a. function more akin to a data router that receives the periodically measured values and processes them for transmission to the processor 50.

[0038] In some embodiments of the disclosure, and by way of example, the KPI used to monitor performance of the pump may be based on a comparison of the actual and reference values of the ratio of differential pressure and power measurements (DP/P). In some embodiments of the disclosure, the KPI may be based on a comparison of the reference to the actual power, P. In one embodiment of the disclosure, the KPI may be determined as presented in Equation 1, below. The KPI may be mathematically equivalent to the inverse of the power degradation factor and may therefore be related to pump degradation. KPI = ^{ac al} = - = -^- = ^Preference Equation 1

Ch ^xCq ^actual

J reference

Where the C factors are defined as follows:

Head Degradation Ch = Ha/H_r Equation 2

Efficiency Degradation Οη = T|a / T|r Equation 3

Flow Degradation C_q = Qa / Qr Equation 4

Power Degradation C_n X Cv Equation 5

[0039] In accordance with various embodiments and regardless of whether the comparison is between DP/P or P alone, the comparison between actual or measured values occurs at a given head or differential pressure. That is, in one embodiment, the comparison is between DP/P (measured) and DP/P (reference) at a given differential pressure across the pump. In another embodiment, the comparison is between P (measured) and P (reference) at a given differential pressure across the pump.

[0040] Measurement of DP/P may be used to measure performance degradation due to any cause, with four typical causes being: (i) wear; (ii) effect of free gas; (iii) effect of viscosity, which may include emulsions; and (iv) loss of electrical insulation in the motor and power cable. It should be appreciated that in certain cases, the pump performance may actually improve, and thus measurement of DP/P is used to measure changes in pump performance rather than degradations in pump performance. For example, where a well production starts with 0% water cut and high oil viscosity, pump performance will be less than that of water. Then, as water cut increases beyond around 40% to 60% (i.e. the inversion point), pump performance improves as the effective viscosity being pumped falls back to water viscosity. A similar phenomenon occurs as GOR (Gas Oil Ratio) reduces with time.

[0041] The method may involve the comparison of actual (i.e., potentially degraded or changed) versus reference pump performance. The reference pump performance may be selected to be the pump curve without degradation or before a change in performance has occurred, which may obtained by testing the pump at the factory, prior to commissioning, using water with a specific gravity (SG) of 1.0. This same process can then be used to calculate degradation at any point in time at which the pump performance is known. Such subsequently obtained data may also be used to define a second point of reference from which to monitor degradation. [0042] Figure IB is a traditional set of centrifugal pump curves presenting head and efficiency plotted as a function of flow rate. However, in order to understand the pump's performance independent of flow rate, the data of Figure IB is plotted independently of flow rate with the ratio of DP/P plotted versus DP, as shown in Figure 2. As used in Figure 2, P represents the pump absorbed power and DP represents the differential pressure across the pump. Notably, DP/P is independent of SG. As a result, difficulties in measuring SG, which may change frequently, are mitigated. The plot shown in Figure 2 is independent of flow rate and the parameters, DP/P and DP, can be measured in-situ for any type of centrifugal pump, including, but not limited to electric submersible pumps (ESPs) typically used in the oil and gas industry. The function, DP/P, plotted in Figure 2 is, as also shown in Figure 3, approximately linear for differential pressures less than those observed at Best Efficiency Point (BEP) and also goes through the origin independently of any change in pump performance.

[0043] A pump produces a curve of DP/P versus DP specific to the pump's geometry. Thus, for a pump a unique function "f can be defined which calculates DP/P as a function of DP for the reference pump performance characteristic curve as expressed in Equation 6 below, which is the mathematical expression for the curve in Figure 2.

DP

— = f(DP) Equation 6

[0044] With regard to Figure 2, the x-axis shows DP which is the difference between the discharge (P_d) and intake (Ρ;) pressures (see Equation 7 below). Downhole ESPs may be fitted with gauges to measure discharge and intake pressures. Similarly, general surface centrifugal pumps may be fitted with gauges to measure suction and discharge pressures thereby allowing DP to be measured.

DP = P_d - Pi Equation 7

[0045] The y-axis of Figure 2 shows the ratio of DP/P. The pump absorbed power may be calculated using electrical measurements taken from an induction motor driving the pump as provided in, e.g., Equation 8 below. By way of example, the induction motor may be a 3- phase induction motor. In instances where the pump is driven by a gas turbine or another prime mover, the shaft power may be measured by a torque transducer or using the prime mover's properties. PF (motor power factor) and r|m (motor efficiency) may be obtained from a motor model and measurements of voltage and current, or through direct measurement of the power factor. _{p =} Q x DP ₌ V_m x I_m x PF x * Equation 8

58847x ¾ 746

[0046] As applied to an electric submersible pump (ESP), measurement of the motor terminal voltage and current may be difficult or impractical. In such instances the switchgear (aka surface) measurements of voltage and current may be used and corrected for cable losses and transformer ratio using the formulae provided as Equation 9 and Equation 10, below:

vm = - ^{a x 1}m Equation 9

V_s = V_d ÷ R and I_m = I_d x R Equations 10A and 10B

[0047] In Equation 9, element "a" is the cable property allowing calculation of the losses in the cable. In Equations 10A and 10B, element "R" is the transformer ratio and allows calculation of motor voltage current as a function of switchgear measured voltage and current.

[0048] After appropriate substitution of Equations 9, 10A and 10B into Equation 4, power is calculated using Equation 1 1 below, as the variables can either be measured or calculated. For traditional surface pumps, voltage is measured at the motor terminals and the corrections in Equation 9, 10A, and 10B may not be required. In most ESP installations, current and voltage at the drive denoted by the subscript "d" may be the available power measurement and therefore the other voltages and currents are expressed as a function of and using Equations 10A and 10B, however, in some installations, measurements are available at the secondary of the step-up transformer in which case V_s and I_m are measured directly. This is the case, where medium voltage drives are used or current and voltage instrumentation is installed at the transformer secondary.

P = "ίν*-* *² * *"* **™** _Equation ! !

746

[0049] Figure 3 presents a plot of DP/P versus DP for a variety of pumps. As shown in Figure 3, each pump, e.g., GN4000, GN3100, GN5600, GN7000, and GN10000, available from Schlumberger Technology Corporation, Houston, Texas, has a unique stage geometry that results in a unique curve and unique BEP (Best Efficiency Point).

[0050] Figures 4A, 4B, and 4C show the effects of frequency on pump performance curves. Figure 4A shows traditional pump curves at four frequencies. Without frequency correction, as shown in Figure 4B, there is a different DP/P versus DP curve for each frequency. Using the affinity laws, DP and DP/P may be corrected to yield a single reference curve independent of frequency, as shown in Figure 4C. In practice, embodiments of the present disclosure may correct measured data for frequency as frequency is known.

[0051] Figures 5 A and 5B show the effect of specific gravity at 1.0, 1.05, 1.1, and 1.15. [0052] Figure 6 depicts another embodiment of the present disclosure, in which power, P, is plotted versus DP as opposed to DP/P versus DP as described above with respect to the pumps referenced by Figure 3. That is, the comparison is between P (measured) and P (reference) at a given differential pressure across the pump. The P versus DP method can be used with the same KPI, although type curve fitting is modified as well as equations 12A and 12B.

[0053] Figure 10 provides a flow diagram that may be used in conjunction with a methodology 1000 of this disclosure. The method 1000 may be embodied in computer readable code on a computer readable medium such that when the processor executes the computer readable code, the processor executes at least a portion of the method.

[0054] By way of example, dynamic data, which are measured values that vary over time, is collected regarding the pump 1002. The dynamic data may include an intake pressure and a discharge pressure for the pump. The dynamic data may further include a voltage, a current, and a frequency as monitored by, for example, respective sensors of the surface switchgear. In some instances, the dynamic data may also include the power factor if a transducer is fitted to the switchgear. In some instances, the fluid being pumped may have a constant, or effectively constant, specific gravity; however, in other, situations, the specific gravity of the fluid being pumped may change as a function of time 1004. Accordingly, the dynamic data may also include the specific gravity of the fluid passing through the pump 1006. The dynamic data may be continuously or periodically sampled, and different values may be sampled at a variety of rates.

[0055] Using the received data, the pump differential pressure may be corrected to the reference differential pressure for any change in specific gravity and the absorbed power may be corrected at 1008. One method for correcting the pump differential pressure is by multiplying the measured pump differential pressure by the ratio of the reference to actual specific gravity. Embodiments of the present disclosure may utilize various methods for obtaining the change in SG. In certain embodiments, this is obtained by calculating the change in differential pressure between the wellhead and discharge pressure of the pump, but this can be any two pressure measurement points preferably with a known differential height, which can be either below or above the pump. Further, and as will be discussed in more detail below, in certain embodiments a power correction may be applied as well. However, it is not necessary to correct the measured power. The result of not correcting for measured power, in an example where reference measurements were taken using water, would be a KPI for a healthy pump that is greater or less than 1.0 (e.g., 0.9), and a change in pump performance may be identified based on the KPI deviating from the uncorrected value, 0.9 for example.

[0056] In cases where calibration is desired, the KPI, which is independent of flowrate, may be leveraged to determine various calibration factors for subsequent application. Turning to Figure 18, a plot of a ratio of differential pressure across the pump to power absorbed by the pump is shown in relation to a reference curve from a factory test. In Figure 18, as above, flowrate measurements are not utilized. The measurements acquired in generating the plot shown in Figure 18 correspond to an approximate lifetime of pump operation; however, measurements corresponding to the few weeks or months following an installation when it can be assumed that the pump is operating in its "as new" condition may be utilized to calibrate the performance model. In this way, a few days' or weeks' worth of data, for example, may be utilized to calibrate the performance model and allow for future forecasting of a relative health or status of the pump being monitored.

[0057] In particular, by calibrating the performance model, errors in measuring and calculating the pump absorbed power may be reduced or eliminated. A further calibration may be used to correct downhole pressure at pump in-situ conditions of absolute pressure and temperature to the reference curve SG (e.g., 1.0 in the event factory test curves are conducted with fresh water). In Figure 18, the calibrations for power and specific gravity are decoupled. First, a calibration shift 1802 along the vertical axis is determined, which is inversely proportional to the pump absorbed power and is independent of specific gravity as explained above. Similarly, a calibration shift 1804 along the horizontal axis is determined, which corrects the downhole measured pressure to an equivalent surface water pressure caused by the specific gravity differences.

[0058] In certain embodiments, the calibration process may comprise two steps. Initially, downhole and surface measurements are corrected at a reference time (e.g. the installation date). Subsequently, a correction is applied to the change in downhole pump specific gravity over time usually due to a change in water cut, which is obtained from the change in pressure drop in the production tubing as used for water cut estimation. This decoupling of the calibration process in the horizontal and vertical axes ensures that there is a unique calibration for power and specific gravity and not an infinite number of combinations of the two.

[0059] As noted above, a power calibration is not required to detect a change in pump performance. For example, if calibration is not performed, the KPI tends to trend at a value other than 1.0 and a deviation from that base line trend value would indicate a change in performance. However, a power calibration may be valuable nonetheless, particularly because the determined calibrated power model may be utilized in other applications that rely on a measurement of power. That is, the pump absorbed power correction factor utilized to calibrate the diagnostic plot in Figure 18 may be utilized in other calculations that rely on a power measurement as well.

[0060] Figure 19 demonstrates a plot of KPI versus time. Upon calibrating the model as described above, the KPI tends to trend near 1.0 for a majority of the life of the test, indicating that the pump is operating in its as new condition without any degradation in performance. Any deviation from 1.0 implies degradation of some sort as actual measured KPI is no longer similar to the reference.

[0061] The time-dependent plot of the KPI shown in Figure 19 can be used as an early indicator of imminent pump failure as shown by the points to the right of the plot that deviate quickly and drastically from a KPI of 1.0.

[0062] Returning generally to Figure 10, the ratio of actual DP/P may be calculated at 1010. The actual DP/P may be plotted against a reference curve of DP/P vs. DP at 1012. As the dynamic data received at 1002 varies over time, new corrections to the pump differential pressure for changes in specific gravity and new ratios of actual DP/P may be calculated, saved, and added to the DP/P versus DP plot at 1012. The DP/P versus DP plot may be output to a computer monitor, stored on computer media, or sent to a printer to produce a physical copy.

[0063] At 1014, the KPI may be calculated as provided, e.g., as shown in Equation 1, above. KPI may also be plotted versus time at 1016. As the dynamic data received at 1002 varies over time, new KPI values are calculated, saved, and added to the KPI plot versus time at 1016. The KPI plot may be output to a computer monitor, stored on computer media, or sent to a printer to produce a physical copy.

[0064] After the KPI is calculated, the monitoring function continues by acquiring real-time data at 1002 and repetition of 1004 through 1018 as disclosed herein.

[0065] At 1018, the KPI plot and the DP/P versus DP plot may be analyzed to determine if pump degradation (or other changes, such as an increase in performance) can be observed as compared to the pump's original performance or against any previously obtained reference point. In some embodiments, the analysis at 1018 may be based on the KPI plot alone in which instance the calculation of DP/P at 1010 may not be conducted. In other embodiments, the analysis at 1018 may be based on the DP/P versus DP plot alone in which instance calculation of KPI at 1014 may not occur. [0066] If degradation (or change in performance) is identified at 1018, further analysis 1020 may occur by establishing a relationship between the ratio of C_q/C as a function of Ch using an operating point and the curve that defines Equation 12B, below. A comparison of the best- fit curve for the actual DP/P data to the reference curve for DP/P may also identify pump degradation. Discrepancies between the best-fit curve and the reference curve are indicative of degradation. Type curve fitting may be used which is enhanced by the property that the curve passes through the origin. However, confidence in the fit type curve improves with an increase in the number of data points at different DP values with a constant, or near constant, degradation and where relationships between the ratio of C /C_q at a given Ch may be defined. Additional DP values may be generated by the pump operator by varying the frequency of, and/or back-pressure on, the pump, and in so doing corroborating the observed degradation at another point on the curve. The type curve may be fitted to the measured data points and overlaid on a plot of DP/P versus DP at 1022. The plot may be displayed on a computer monitor, stored in electronic media, or sent to a printer to generate a physical copy.

[0067] With regard to the KPI plot, the onset of pump degradation may be identified when the ratio of (DP/P)_actuai/(DP/P)_reference deviates as a function of time. By way of example, the data may be calibrated such that the KPI value is set to 1.0 at the reference time and degradation may be identified as KPI value deviates from 1.0. As shown in Figure 13, during operational periods of the first three years, the KPI was 1.0 (except during transient stops and starts, which may create noise in the plot). However, in the final year of operation, the KPI can be seen jumping to >2.0, which may indicate pump degradation. This also identifies a period of ongoing degradation.

[0068] If degradation is (or change in performance) is identified, further analysis may occur at 1026. The additional analysis may include consideration of the age of the pump, sand production data, insulation measurements, and PVT data 1024. PVT data may include, but is not limited to, oil gravity, bubble point, solution gas-to-oil ratio, and oil formation factor. The additional analysis may generate a revised pump curve using the calculated head, efficiency, and flow rate degradation. In addition to performing additional analysis, or in the alternative, certain embodiments of the present disclosure may include taking a remedial or other corrective action in response to a determination that the pump is expected to fail or experience unacceptably-degraded (e.g. , above a predetermined threshold) performance. The action taken may be automated in some instances, such that a particular type of determination automatically results in the action being carried out. Actions taken may include altering pump operating parameters (e.g., operating frequency) or surface process parameters (e.g., choke or control valve positions) to prolong pump operational life, stopping the pump temporarily, and/or providing a warning to a local operator, control room, or a regional surveillance center.

[0069] For purposes of the present disclosure, pump degradation is defined by a factor from 0 to 1 as per the formulae in Equations 2, 3, 4, and 5, reproduced below for convenience. The subscript "a" refers to the actual performance while the subscript "r" refers to the reference performance, which, as mentioned previously, may be the factory test curve. In some embodiments, degradation may be measured relative to a known in-situ pump performance, which becomes the reference denoted by the subscript "r' and the same process and equations apply.

Head Degradation Ch = H_a/Hr Equation 2

Efficiency Degradation C_n = r\_a I T|r Equation 3

Flow Degradation Cq = Qa / Qr Equation 4

Power Degradation C_n x Ci- Equation 5

[0070] The present method may be based on the assumption that the shape of a given pump curve does not change with degradation and, therefore, the same degradation factor applies to all the points on the pump curve, i.e., across the full operating range of the pump. However, in other embodiments, changes in the shape of a pump curve with degradation may be observed during experimentation and thus determined, quantified, or defined in an experimental manner

[0071] Figures 7A, 7B, 8A, 8B, 9A, and 9B illustrate how each of the foregoing factors (Ch, ϋη, Cq, and C_p) effect the DP/P vs DP curve. Figure 7A illustrates the effect of head degradation. As shown in Figure 7B the plot of DP/P vs DP shifts to the left as Ch decreases. Figure 8A illustrates the effect of efficiency degradation. As shown in Figure 8B, the plot of DP/P vs DP shifts downward as C decreases. Figure 9A illustrates the effect of flow rate degradation. As shown in Figure 9B, the plot of DP/P vs DP shifts upwardly as C_q decreases. While the degradation effects demonstrated in Figures 7A - 9B isolate the effect, in practice these forms of degradation occur concomitantly.

[0072] Collectively, these figures indicate relationships and correlations that, when coupled with corrections for any change in SG and/or frequency between the reference curve and the time at which the actual measurements are taken, may allow for the derivation of mathematical expressions relating measured DP/P to DP using the reference function and the degradation factors: ^ = f(DP) at SGr and Fr Equation 12A

Equation 12B

[0073] Equations 12A and 12 B provide the general equations relating measured DP/P to DP using the reference function and the degradation factors.

[0074] Equation 12B includes the following two additional corrections in order to remove the effect of changing SG and frequency and therefore isolate the effect of degradation. As used in Equation 12B, the following corrections are used:

[0075] F_r/F_a - The ratio of reference to actual frequency and is included in Equation 12B as the function f is for a given frequency Fr, whereas measurements of DP/P may be at another frequency F_a. This correction uses known affinity laws for centrifugal pumps.

[0076] SGr/SGa - The ratio of reference to actual specific gravity. The absolute SG is not required; instead, the disclosure uses the relative change in SG. For applications in single phase applications, such as water or oil, this ratio is 1. For ESPs or other centrifugal pumps that may pump three phase fluids, the ratio of SG can be estimated by several methods, two of which are briefly described below:

[0077] Method 1 : In low gas-to-oil ratio ("GOR") wells, the SG may be considered a function of WC (water cut) and it is sufficient to use WC measurements to calculate SG.

[0078] Method 2: Using the trend of pressure drop in the production tubing above the ESP as a proxy for change in SG. Additionally, this method does not rely on calibration against a measured SG as the change in SG relative to the reference point in time is used, which is a reasonable approximation, and thus calibration may be preferable if available.

[0079] Returning to Figure 10, following analysis 1026, the calculation of Ch, C_q and C_n may occur where there is a continuous or ongoing, or near continuous, change of degradation with time. As there are three unknowns, three equations/relationships may be used to resolve Ch, Cq and C . The first equation is provided by the KPI, which is calculated in 1014 using Equation 1. A second equation may be provided by the type curve fitting already described above as part of 1020/1022 in Figure 10 and utilizing Equation 12B to establish a relationship between the ratio of Cr C_q and Ch. The first two relationships are independent of the type of degradation (e.g., gas, viscosity, wear, and insulation loss) and therefore lend themselves well to automation. [0080] However, a third equation used to resolve the 3 unknowns may require some knowledge or hypothesis of the most likely cause of degradation (e.g., gas, viscosity, wear, or insulation loss). The hypothesis may be based on observed fluid properties as well as reservoir geology as described in 1024 and 1026 of Figure 10. The third equation may be of the form ~ f(Cq, C , ai, a₂... On), where ai, a₂... a_n are coefficients accounting for stage geometry, and n is the total number of these coefficients. The exact relation will depend on the mechanism of performance changes. The values of ai, 012 ... a_n may be determined using models or laboratory test data. Not all of the independent variables (C_q, Ch, on, a₂... a_n) may be required in the equation. Note that where more than three equations are available, three of these can be combined to resolve the three performance correction factors, with additional equations being leveraged to corroborate the answers found.

[0081] As one example, for instances where analysis 1026 suggests gassy conditions, the efficiency correction factor, C_n, may be considered to be approximately equal to head correction factor, Ch, as provided by Equation 13: C_n = Ch. Alternate equations may be used instead and Equation 13 is exemplary in this regard. Using the approximation provided by Equation 13, the correction factors may be resolved with the KPI and type curve established at 1020/1022. If Cq is close to 1.0, which is often the case when the fluid is gassy and is not also viscous, then it may be difficult to detect performance changes when operating the pump at flow rates greater than BEP. This can be circumvented by temporarily choking the pump and producing at lower flow rates. Figure 16 illustrates the effect of performance change due to gassy conditions when C_q = 1.0.

[0082] As another example, where the analysis 1026 suggests the performance changes may have been caused primarily by viscous conditions, the relationship between efficiency, head, and flow correction factors will be represented by a different equation having the form C_n = f(C_q, Ch, on, a₂... a_n). An example equation could be C_n= on x C_q x Ch, although alternate equations may be used. The factor on is in this example a stage geometry specific factor related to energy losses, which can be obtained from modelling or lab test data on the specific stage geometry. Figure 16 provides a diagnostic plot of the expected effect of performance changes due to viscosity. This relationship in conjunction with the two relationships from 1014 and 1020 can be sufficient to resolve the three correction factor unknowns.

[0083] As yet another example, where the analysis 1020 suggests that the performance changes may have been caused by wear, a relationship between efficiency, flow, and head correction factors will be represented by a different equation, again of the form C = f(C_q, Ch, on, α₂... an). One example equation could be Equation 15: C_q = Ch ^l where on > 1.5. Using Equation 15, the KPI, and the curve fit of 1022, the performance correction factors can be resolved. In this example, the factor on can be obtained from modelling or lab test data on the specific stage geometry; in certain other embodiments it may be approximated to 1.5.

[0084] The foregoing method of the disclosure was used to identify the occurrence and cause of degradation in a centrifugal pump, such as an ESP. Figure 11 shows a particular embodiment in which an electric submersible pump 1104 is disposed in well 1102 and receives electric power from source 1106. A plurality of sensors collects data regarding the performance of the pump at 1108. The data includes, but is not limited to, the frequency, current, and voltage of the VSD, and the intake and discharge pressure of the pump. Other data collected may include wellhead pressure, wellhead temperature, intake temperature, or motor temperature, as shown in Figure 11. The data may be stored in electronic media at 1110, such as on a computer hard drive, with computation and analysis performed by computer/processor 1112 and results displayed on monitor 1114. Figure 11 relates generally to activities described at 1002 of Figure 10.

[0085] Figure 12 shows a sample plot of the ratio of change in SG versus time. Figure 12 relates generally to activities described at 1006 and 1008 of Figure 10.

[0086] Figure 13 shows the degradation of KPI for the pump 1104 depicted in Figure 11. During the three year period, indicated by numeral 1, the data shows a KPI of 1.0, except during transient stops and starts which may be the "noise" in Figure 14 below. The second period, indicated by numeral 2, evidences a small increase in KPI due to inaccuracy in calculating motor power factor (PF) and efficiency when the load factor is less than 40%. During the final year of operation, indicated by numeral 3, the KPI jumps to 2.0 indicating pump degradation. Figure 13 relates generally to activities described at step 1014 of Figure 10.

[0087] Figure 14 presents a diagnostic plot, and best-fit curves, for DP/P versus DP- corrected, where DP -corrected is the product of DP-actual, the square of the ratio of F_r/F_a, and the ratio of the reference to actual SG. The measured data matches the reference curve for the first 1 ,200 days, accounting for the noise, indicating that the pump has not degraded. However, after 1,200 days, the best- fit curve indicates substantial deterioration. Figures 18 and 19, discussed above, illustrate similar plots but for different wells, which demonstrates that in various examples, a KPI that deviates from a reference value in either direction may indicate a change or degradation in pump performance. In Figure 13, for example, the KPI trends above 1.0, indicating a change or possible degradation in pump performance. Conversely, in Figure 19, for example, the KPI trends below 1.0, but also indicates a change or possible degradation in pump performance. That is, the change or degradation in pump performance may be indicated by a deviation of the KPI from the reference regardless of the direction of the deviation.

[0088] Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the examples. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words "means for" together with an associated function.

Claims

CLAIMS What is claimed is:

1. A method for monitoring a pump comprising:

determining a measured power absorbed by the pump;

generating, with a processor, a performance indicator by comparing the measured power to a reference power for the pump;

populating a log of performance indicators; and

comparing a performance indicator to prior performance indicators in the log to identify changes in the performance indicator as a function of time.

2. The method of claim 1 further comprising:

determining a measured differential pressure across a pump;

generating, with the processor, a measured ratio of differential pressure to power for the pump;

wherein the performance indicator is generated by comparing the measured ratio of differential pressure to power to a reference ratio of differential pressure to power for the pump.

3. The method of claim 2, wherein determining the differential pressure includes correcting for changes in specific gravity.

4. The method of claim 2, comprising populating a log of ratios of differential pressure to power for the pump.

5. The method of claim 4, comprising displaying a plot of the ratios as a function of differential pressure.

6. The method of claim 2, comprising comparing a best fit type curve for the ratio of actual differential pressure to power data to a reference curve of differential pressure to power.

7. The method of claim 1, wherein determining power absorbed by the pump includes correcting for cable losses.

8. The method of claim 1, wherein determining power absorbed by the pump includes correcting for a transformer ratio.

9. The method of claim 1, further comprising displaying a plot of performance indicators as a function of time.

10. The method of claim 1, comprising establishing at least one relationship between two or more degradation factors.

1 1. The method of claim 10, comprising using the at least one relationship to calculate the degradation factors.

12. The method of claim 1, comprising generating an alert in response to a change in the performance indicator as a function of time relative to a predetermined value.

13. The method of claim 1, further comprising:

generating a power calibration factor based on a difference between the measured power absorbed by the pump during a time period in which the pump is confirmed to be healthy and a reference value for power absorbed by the pump; or

generating a specific gravity calibration factor based on a difference between a measured pressure near the pump during a time period in which the pump is confirmed to be healthy and a reference pressure.

14. A system for monitoring a pump comprising:

a pump;

a power source configured to supply electricity to the pump; and

a processor configured to:

receive data related to a voltage from the power source, a current from the power source, and a frequency from the power source;

based on the received data, generate an indication of measured power absorbed by the pump;

generate a performance indicator based on a comparison of the measured power to a reference power absorbed by the pump.

15. The system of claim 14 wherein the processor is further configured to:

receive data related an intake pressure of the pump and a discharge pressure of the pump;

based on the received data, generate an indication of measured differential pressure across the pump;

generate a measured ratio of differential pressure to power for the pump;

wherein the performance indicator is generated based on a comparison of the measured ratio of differential pressure to power to a reference ratio of differential pressure to power for the pump.

16. The system of claim 15, wherein the processor is further configured to calculate at least one degradation factor related to the pump.

17. The system of claim 15, wherein the processor is further configured to compare a performance indicator with a previously calculated performance indicator.

18. The system of claim 17, wherein the processor is further configured to generate a visual representation of the comparison of the performance indicator with a previously calculated performance indicator on an associated graphical display unit.

19. The system of claim 14, wherein the processor is further configured to:

generate a power calibration factor based on a difference between the measured power absorbed by the pump during a time period in which the pump is confirmed to be healthy and a reference value for power absorbed by the pump; or generate a specific gravity calibration factor based on a difference between a measured pressure near the pump during a time period in which the pump is confirmed to be healthy and a reference pressure.

20. A non-transitory computer readable medium programmed with computer readable code that, upon execution by a processor, causes the processor to:

receive data related to a voltage, a current, and a frequency from a power source; based on the received data, generate an indication of measured power absorbed by the pump; generate a performance indicator based on a comparison of the measured power to a reference power absorbed by the pump; and

create a log of performance indicators.

21. The non-transitory computer readable medium of claim 20 wherein execution of the code by the processor further causes the processor to:

generate a measured ratio of differential pressure to power for the pump;

22. The non-transitory computer readable medium of claim 20 wherein execution of the code by the processor further causes the processor to control a graphical display to present a plot of performance indicators as a function of time.

23. The non-transitory computer readable medium of claim 20 wherein execution of the code by the processor further causes the processor to:

establish at least one relationship between two or more degradation factors; and calculate at least one degradation factor.