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7th European Electric Submersible Pump Round Table Aberdeen Section

ESP Monitoring – Where’s your speedometer?

A.J. (Sandy) Williams, Julian Cudmore, Stephen Beattie (Phoenix Petroleum Services)

Abstract

It is estimated that some two percent of all electrical submersible pumps (ESPs) in the world have some form of downhole sensor installed. This is a very small sensor population in relation to the number of ESPs. Reliable sensor technology has been available for a number of years and yet the majority of ESPs do not have sensors installed. Part of the reason that sensors are not installed and used more widely is because of the outdated techniques used by ESP manufacturers to diagnose and troubleshoot ESP performance.

Operators can use a downhole sensor to obtain a direct measurement of ESP and well performance. Direct accurate measurements are of more value than a simulated or calculated value. This paper will outline the direct measurements that can be taken and illustrate how they can be used, real-time, to increase production, diagnose well and ESP performance and achieve protection and control of the ESP system to extend ESP runlife.

The use of direct measurements of performance, control, analysis and design are the key steps in most continuous improvement processes (figure 1). Use of measured data from a downhole sensor is the first step in implementing a continuous improvement process for the ESP-produced well. However, to benefit from this data we need to change the way we design, operate, troubleshoot and optimise ESPs and use pressures rather than electrical parameters. This paper will discuss how monitoring of ESPs has evolved and identify the steps that need to be taken to make use of the data obtained from a downhole sensor.

Case histories will be presented that illustrate how sensor data has been applied to:

1. identify opportunities to increase production; 2. identify wellbore damage following a workover; 3. demonstrate the importance of fluid properties on ESP design and well production.

This paper presents the case history data and subsequent well analysis using the gradient traverse plot technique.1

Introduction

This paper describes three case histories that demonstrate how downhole sensor data can be used to determine information that is vital to understanding and improving well and ESP performance. The case histories and consequent benefits were achieved as a result of using the data from the downhole sensor and applying an analysis technique that considers the well as a hydraulic system.

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Most ESP analysis, troubleshooting and control systems are based on the use of electrical parameters to predict ESP and well performance. This paper will discuss the evolution of ESP monitoring and why our industry still uses electrical parameters to monitor ESPs. A discussion of the philosophy of measurement will be undertaken and related to the benefit of using measured pressures to diagnose performance of the ESP produced well.

The use of directly measured pressures and temperatures and their benefits for control of the ESP system and prevention of premature system failure will be highlighted.

Well modelling techniques will then be discussed in relation to the ESP-produced well and the relative merits of considering the well as a hydraulic system.

The economics related to the cost of a downhole sensor will be considered in relation to the benefit that can be derived from the use of the sensor.

Philosophy of Measurement

The primary reason for running a downhole sensor is to get an accurate real-time measurement of an ESP’s operating parameters. Before we consider measurement of ESP operating parameters, let’s consider an analogy for how measurements can be taken and the relative value of the type of measurement. Consider a car travelling from town A to town B. Supposing we wish to know the velocity of the car, there are a number of ways this can be determined: if we know the distance from A to B we can calculate the velocity based on the time to cover the distance (equivalent to average velocity); a police speed camera can be used to determine the speed of the vehicle (instantaneous velocity); or using a sophisticated onboard computer we can calculate the velocity of the vehicle based on the fuel consumption of the vehicle. The reality is that none of these methods are required because we have a simple device called a speedometer, which gives us a real-time indication of velocity at any point in time. The principle here is if you want to know something that can be measured directly then measure it!

ESP Monitoring & Control - History

The evolution of monitoring in relation to ESPs is such that in domestic land operation in the USA, when running an ESP direct on line (i.e. no variable speed drive), the only variable once the pump had been installed was wellhead pressure. The challenge to the operator was to design a pump and get maximum production without creating a pump-off situation. In order to determine the drawdown of the pump in the wellbore, fluid shots were taken to determine the fluid level. Fluid shots are a valuable tool in the absence of any other technology but can be inaccurate due to effects such as foamy crude or completion configuration, i.e. a liner top. (Figure 2 shows a graph of measured bottom hole pressure versus time for a fluid shot and downhole sensor2). As ESP control systems evolved it became possible to protect the ESP by causing a pump shutdown based on underload and overload current settings – indicative of an adverse operating condition.

The next step in the evolution of ESP technology was the variable speed drive (VSD): this device gives operators an additional method by which to control ESP operation. The main advantage of the VSD is that it allows the operator to change the speed of the ESP to account for uncertainty in productivity index of the well or changing well conditions. These systems are still set up to trip on overload and underload settings.

The next major landmark in the evolution of ESP monitoring and control was the development of downhole sensors. Initial attempts to apply downhole sensor technology, as with most new technologies, were unsuccessful. The challenges to producing a sensor that could operate in

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conjunction with an ESP were downhole temperature, communication method (up the ESP power cable or separate line) and power quality. However, as an industry, over time, we have developed reliable downhole monitoring systems that routinely outlive the ESP system – some systems, having outlived the ESP several times, have been re-run as many as five times.

ESP Monitoring and Control - Today

Initial attempts to develop sensors focused on measuring one pressure and one temperature, usually at the pump intake. Sensors now exist that can measure intake pressure, discharge pressure, downhole flowrate, intake temperature, motor winding temperature, discharge temperature, system vibration and electrical integrity of the system. The latest development in respect of performing downhole measurements around an ESP hinges on the application of fibre optic technology.

Table 1 provides a summary of the types of monitoring that may be performed in relation to an ESP completion.

Of the two percent of ESPs with downhole sensors installed, very few sensors are used for more than obtaining an accurate pump intake pressure (Pi). In reality very few operators use this parameter to control the ESP and maintain a constant pump intake pressure (Pi), thereby increasing production. Using existing technology this could be easily achieved.

Through the use of ESP operating parameters such as discharge pressure (Pd), intake temperature (Ti), motor temperature (Tm) and vibration (Vib) it is also possible to understand the well and ESP as a system. Such understanding leads to better system design and a continuous improvement process, based on measured known data.

The reality is that even when the most sophisticated downhole sensors are used to measure ESP operating parameters, these parameters are not used to best advantage. Current (no pun intended!) ESP analysis or monitoring is still based on electrical parameters (amps). Using electrical parameters to analyse ESP performance is analogous to the calculation of velocity based on fuel consumption in the example of how to measure a car’s velocity.

As an industry we have not fully adapted to perform ESP diagnosis and analysis based on directly measured parameters.

This fact is borne out by the revelation that the majority of control systems for ESPs are still set up to control on amps. Systems that have downhole sensors installed are set up without any form of protection, based on the measured parameters (pressures and temperatures). See figure3 for an example of an ESP failure which could have been prevented had the sensor parameters been used.

The benefit of using downhole sensor parameters to protect the ESP has been proven. As soon as one operator started using the measured ESP parameters to initiate pump shutdowns, when an abnormal operating condition was experienced, pump runlife in the field doubled! Another operator was able to demonstrate a value of $25MM in terms of prevented workovers and increased production for an associated sensor purchase cost of $2MM - compelling evidence for the value of ESP monitoring using downhole sensors!

Production Optimisation

Figure 4 shows a typical pressure response in a well with an ESP installed. If the pump intake and discharge pressures are not known and instead guessed, simulated or measured inaccurately, it changes the whole pressure response within the wellbore. Knowledge of these values is required to

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ensure that we understand the ESP operating conditions, namely that the pump is optimally sized and that production is optimised.

From a production standpoint the most important parameters are the pressures across the ESP: after all the function of the ESP is to add energy and cause a pressure change in the wellbore to allow the well to flow at a higher rate. If we measure Pi and Pd we know the exact pressure response in the wellbore and can therefore consider the wellbore as a hydraulic system. When ESP discharge and intake pressures are known and used in conjunction with the ESP performance curve they can be used to validate or determine a number of useful operating conditions such as: validate fluid properties; plot pressure across the pump (dP) vs. frequency; infer downhole flowrate; and calculate bottomhole flowing pressure. Table 2 provides a summary of the information that can be gleaned using two measured pressures.

As an industry we tend to understand a naturally flowing well in terms of pressure and depth. If we want to analyse a naturally flowing well we use well test data, pressure information from a flowing gradient survey and a nodal analysis software package. The pressure and flowrate information provide known measured data points to validate our software model. Our methodology is to validate our fluid property assumptions by using our software to match a predicted pressure to a measured pressure and then, having accurately validated the model, we can extrapolate it to interpret changing wellbore conditions. The important point of this course of action is that we, in validating the fluid properties for the produced fluids, understand and model the well from a hydraulic standpoint (pressure and depth).

When we use an ESP in a well we tend to stick the pump in the wellbore and immediately start to consider the well response in terms of head and amps. Neither of these parameters is a direct measurement of well performance! If we consider the traditional approach to ESP design and well analysis, the wellbore pressure response (tubing flow regime) is converted into feet of head. Electrical parameters are then used to calculate how much work the motor is doing and therefore how much head the pump is producing. The well pressure response is then plotted on a flow versus head curve for the particular ESP, with a cross representing the operating point of the system. This technique works after a fashion and was necessary when it was the only tool available. Today you will find that the majority of ESP company personnel still talk about static and dynamic fluid levels and total dynamic head rather than static reservoir pressure, bottomhole flowing pressure or pump dP. The reality is a better method exists.

ESP Monitoring and Control – The Way Ahead

As operators and ESP related service companies, our challenge is to progress to considering ESP-produced wells as hydraulic systems. This involves directly measuring the performance of the ESP in terms of pressure. Having obtained the measurements, we can directly control the ESP, diagnose ESP performance and optimise production. After all, the basis of continuous improvement processes is to measure what you do and try to implement improvements, based on the measured information. The best way to improve our application of ESPs is to measure ESP performance (speedometer!) using a downhole sensor.

To benefit from the data that can be obtained from downhole sensors we need to change the way our industry looks at design, optimisation and troubleshooting of ESP systems. If we consider the ESP to be the cause of a pressure change in the wellbore and then analyse the well from a hydraulic standpoint, we can consider the well using the same technique as we would for a free flowing well. The benefit of this approach is that we consider the ESP-produced well as a hydraulic system and shift the focus from the ESP to the producing well – where the barrels (hence $) come from. Commercial software currently exists that can perform analysis based on ESP pressure response in the wellbore. Such software tends to be better for analysis and troubleshooting of ESP produced wells than the programs used by ESP manufacturers.

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From a control standpoint switching to control on intake pressure makes more sense than controlling on frequency or amp load: after all intake pressure can be controlled, in relation to the bubble point, to maintain a constant bottomhole pressure above a pressure that would cause excessive sand production or just to maintain a constant intake pressure – amps merely correspond to the work of the motor and frequency to the speed of the motor. It is interesting to note that when an ESPCP system is run with a downhole sensor, it is often set up to maintain a constant Pi rather than a constant RPM – why should PCPs be different from ESPs in this respect?

In addition to maximising well production, through the use of sensor data, it is possible to protect the ESP using surface control systems. Applying such control systems using appropriate parameters to control provides a method to prevent “automatically” a pump from being operated in a condition that could result in equipment failure. To facilitate this the surface control system has to be configured to cause an alarm or shut down (trip) the pump when such a condition is detected.

The rationale as to whether a pump trip is used in preference to an alarm will be a function of location, operating philosophy and the availability of personnel to respond to an alarm scenario. For example on an isolated land application, where no one is available to respond to an alarm, it would be more sensible to trip the pump, whereas on an offshore platform an alarm may be the preferred approach.

The following provides a summary of the key parameters that can be measured using a downhole sensor, with the associated control philosophy for each:

Pump Intake Pressure (Pi) should be used to prevent pump-off or to prevent the well from being drawn down below a given pressure (bubble point or a minimum bottomhole flowing pressure). For example, Pi may be controlled at above 200 psi in a well where gas breakout becomes excessive and causes pump operating problems below this value. In this case the surface control system would be configured to trigger an alarm at 200 psi intake pressure and to trip the pump if the intake pressure reduced further to 175 psi.

Pump Discharge Pressure (Pd) will immediately respond to changes in specific gravity of the produced fluid (watercut or gas), changes in surface pressure (wellhead) and can be used to prevent a pump being deadheaded or operated in a low flow scenario. The setting of the trip/alarm should be based on a calculated maximum value for Pd during normal operating conditions or the value can be set at normal operating Pd plus a margin (for example 50 psi). The value can also be determined practically in the field by performing a shut-in test, i.e. observing the measured Pd and setting the trip level below this value.

Knowledge of both pressures gives an exact knowledge of the work done by the pump at any moment in time and is of particular use in complex ESP situations, such as high viscosity fluids or gassy wells.

Pump Pressure Differential (dP) can be used to ensure that the ESP is run within range. For a given pump frequency and with a known density of produced fluids, a minimum and maximum pump dP corresponding to the upthrust and downthrust range on the ESP can be set to ensure that the pump is operated in range. Consideration of figure 5 will illustrate this concept by demonstrating a pump operating ‘in range’: the minimum and maximum operating points correspond to a head of 3774 ft and 1957ft at the operating frequency. The produced fluids in this case have average specific gravity (s.g.) of 0.95, by using the relationship:

dP (psi)= Head (ft) x s.g. x 0.433 (psi/ft)

A minimum and maximum dP of 1552 and 805 psi is calculated in accordance with the efficiency range of the pump. These values would be programmed into the surface control system so that an alarm would trigger if pump dP increased above 1552 psi; a pump trip could also be set if pump dP

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continued to increase, an indication that the pump is moving more into a low flow or potentially damaging downthrust condition.

Motor Temperature (Tm) can be motor winding temperature or motor oil temperature. Where possible it is preferable to monitor motor winding temperature, as the winding temperature always increases more rapidly in response to ESP problems. The trip/alarm should be set to activate at approx 20 deg C above normal operating temperature.

Pump intake temperature (Ti) acts as a back-up to motor temperature and would be set to trip/alarm at the same value as the motor temperature reading. However, motor temperature is almost always likely to respond first. Changing intake temperature can also be an indicator of change in well flowrate.

Vibration (Vib) is an indirect measurement of ESP performance since, like amps, it includes mechanical (e.g. sand, wear), electrical (e.g. frequency) and hydraulic (e.g. gas, viscosity) components3. It is thus difficult to interpret an exact, absolute value of vibration – rather the trend of vibration is important and can indicate a range of problem conditions or change in normal operating conditions such as:

• change in frequency (pump speed) and operation around resonant frequencies; • change in wellhead pressure (by surface choke closure); • increase in well watercut and indication of emulsions; • onset or increase in solids (sand/scale) production and tracking pump wear; • start of gas locking; • change of pump/motor temperatures caused by severe upthrust/downthrust operation.

Generally vibration would only be set up as an alarm function.

Other trips can also be set on current leakage or flow. Additionally a backspin relay can be used to prevent re-start of the pump following a shutdown while fluid is still draining through the pump.

If the surface control system displays an alarm or the pump trips, it is important to understand why the pump tripped. Prior to restarting a pump the effort should be taken to examine the logged sensor data to determine the cause of the shut down. Many premature pump failures could be avoided if the time were taken to understand why a trip or alarm occurred.

To use such parameters effectively to control and protect the ESP, an input card is usually required on the VSD to allow the pump to be controlled real-time using parameters measured by the downhole sensor. This simple step can have a significant effect on ESP runlife. Control of the ESP using measured parameters in combination with a change in approach to consider the ESP-produced well as a hydraulic system can provide the operator with longer runlife, increased production and valuable information for design of future systems – a simple method to provide continuous improvement for ESPs.

Economics

The decision not to run a downhole sensor with an ESP inevitably arises from the cost! A reliable downhole sensor can cost anything between $20,000 - $80,000, what some may judge to be a high cost! Consideration of table 3 shows that for a production rate of 1000 bopd at an oil price of $10/bbl a sensor can pay for itself in between 2 and 8 days. (Note: this takes no account of the rig cost, replacement ESP cost nor deferred production cost of a failed ESP). If used to control the ESP the downhole sensor provides opportunity to prevent failure of the ESP, which can prolong life of the

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system. If the downhole sensor data is also used to analyse the ESP system and optimise production, the value of the sensor is increased further.

Case Histories

The following case histories are all based on analysis of data that was obtained from a downhole sensor. The gradient traverse plots, presented as part of the analysis, was produced using a simplistic excel based nodal analysis program. All Phoenix field engineers are trained in the use of such software and are expected to perform an analysis during well start-up or on a regular basis to ensure optimum use of the data from the downhole sensor. Calculations using such software can also form the basis for setting up of control and protection systems on the ESP.

The following case histories have been selected because they illustrate examples of opportunities for using the data from the downhole sensor to increase production.

Case History 1 - Opportunity to upsize the ESP

This example is illustrative of a field that had been produced for several years using ESPs. Some sensors had been run in the field but had proven to be unreliable. As such, most of the ESPs were designed, analysed and optimised on the basis of electrical parameters and fluid shots rather than reliable sensor data. The operator of the field believed that the reservoir should be capable of supporting higher production rates. By using a sensor to measure intake and discharge pressure it was possible to analyse the ESP performance, determine the inflow characteristics of the well and predict production rates using a larger ESP.

Figure 6 shows the results of the analysis and indicates that the ESP is operating in ‘upthrust’ while producing at a rate of 9435 bfpd. The well has relatively high water cut and therefore is insensitive to the bubble point of the crude and gas at the pump intake. A prediction indicated that the well could be produced with a larger ESP, reducing the bottom hole flowing pressure, to produce an additional 3000 bfpd.

A series of workovers was implemented to increase ESP size in the field. In addition to the benefits of increased production from the wells, the downhole sensor is used to control the pump, prevent a pump-off situation and shutdown the pump in the case of an operating condition, such as temperature or pressure outwith the normal envelope of the pump.

Figure 7 shows the results on an analysis performed on the same well after it had been worked over to increase the pump size. The well is now producing at 12265 bfpd, a production increase of 2830 bfpd. Note that in this case the well is being produced at higher wellhead pressure than used for the prediction. If the wellhead pressure were lowered the well would be capable of producing the additional 3000bfpd, per the prediction.

Case History 2 – Identification of production interval damage

An ESP in the well in question had run for three years at a rate of approximately 6000 BFPD before the pump failed. Following a workover to replace the ESP the well was producing at 1900 stb/d, the operator and the ESP manufacturer suspected a pump problem. Using information from a downhole sensor measuring two pressures, it was possible to confirm that the pump was operating correctly for the number of stages and operating frequency, albeit at a lower flowrate for the expected productivity of the well. A calculation of inflow characteristics indicated a PI of 1.07 stb/d, much lower than expected for this well. Wellbore damage was believed to be the cause of loss of productivity. An acid

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job was recommended to remove the damage and restore production to the 6000 bfpd that had been achieved previously.

Case History 3 – The effect of friction on pump sizing, flowrate and tubing size.

The previous examples have been simplistic, in that they have demonstrated an ability to increase production, provided we look beyond what is happening in the ESP: consider the well from a hydraulic standpoint and consider the well’s productivity. This example is more complicated and illustrates the importance of understanding well fluid properties to size the ESP and also identifies the opportunity for increased production from this well as a free flowing well or one with a larger ESP and larger tubing.

Consideration of figure 8 shows a trend plot of downhole sensor parameters. It can be observed that while the pump is running, a pump dP of approx 450 psi is created. The well is producing at a rate of 5750 stbl/d, the pump is operating in range and all parameters are within a normal operating environment. Figure 9 shows operating point in relation to the pump curve.

A few hours later the trend plot shows that the pump has shut down. In this scenario the well is free flowing but a pressure drop of 54 psi occurs across the ESP, due to the pressure drop of fluid flowing through the ESP (figure 10). Flowrate is estimated to be 2280 bfpd. However, if a means of removing the pressure drop through the pump could be achieved using an auto flow sub (figure 11) or a sliding sleeve, an additional 1000 stbl/d could be achieved.

Reconsidering the scenario with the pump running, a ‘happy pump’ with stable electrical parameters operating in the middle of its operating curve, it is worth considering the well from a hydraulic standpoint. Analysis shows that a production rate of 5750 bfpd is being achieved through 3 ½” production tubing with a frictional pressure drop of 274psi. For a well with a PI of 33 stbl/day/psi this represents a ‘large’ loss in production.

A predictive analysis performed using a larger ESP and a larger tubing size (4 ½” instead of 3 ½”) demonstrated that a production increase of 2150 bfpd could be achieved. See figure 12.

This case history illustrates multiple opportunities for production increase. Firstly the well can be free flowed, bypassing the pump to gain an additional 1000 bfpd. Secondly, using a larger pump and larger tubing the well can produce an additional 2150 bfpd. This example illustrates the importance of considering the well and ESP as a hydraulic system. Considering the producing well in this manner identifies opportunities to increase production, based on well inflow capability: a traditional approach of just looking at the ESP would be unlikely to identify such opportunities for production increase.

Conclusions

Monitoring of ESPs using downhole sensor data provides an opportunity to diagnose ESP performance from a hydraulic standpoint - which relates directly to well production and improved ESP reliability. Downhole sensor data provides an immediate direct accurate measurement of ESP performance (analogous to the speedometer in your car).

Reliance purely on electrical parameters for the interpretation and diagnosis of ESP performance is an impediment to the progress of the application of ESPs. Consideration of the well, produced using an ESP as a hydraulic system rather than just an electrical system, can further the application of ESP technology.

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ESP runlife can be improved if surface control systems are set-up to control the ESP, based on parameters directly measured using a downhole sensor.

The cost of a downhole sensor in relation to the opportunities for increased production, prevention of an ESP failure or deferred production in relation to the sensor cost is minimal.

The application and reliability of ESP technology can be improved if the ESP manufacturers adopt the ‘continuous improvement process’ of using measured pressure data, in addition to using electrical parameters, to understand and interpret well performance.

References 1. Williams, A.J., “Demsytifying ESPs: A technique to make your ESP talk to you” presented at

6th European Electric Submersible Pump Round Table Feb 15-16 of 2000. 2. Moffat, T., Conn, T., Applications of Real-Time Well Monitoring Systems presented at

Southwestern conference, Lubbock February 2000. 3. Baillie, A.R., Williams, A.J., Cudmore, J., “Vibration: How can we use it to prolong runlife?”

SPE Electric Submersible Pump Workshop Houston, Texas April 25-27 2001.

Tables & Figures

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Figure 1 – Representation of a continuous improvement process.

Figure 2 – Actual well data showing discrepancies between true bottomhole pressure and calculated bottomhole pressure from acoustic fluid shots.

0

500

1000

1500

2000

2500

Jun/1 Jun/25 Jul/20 Aug/13 Sep/7

Actual BottomholePressure

Bottomhole PressureFrom acoustic fluid shots

Error

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Level of Monitoring What is measured Benefit Electrical parameters ESP controlled diagnosed and

operated purely on electrical parameters

Lowest equipment cost. Least added value

Fluid levels monitored Occasional sonic logs taken to determine intake pressure

Intake pressure measurement inaccurate, potential for analysis based on incorrect data.

Basic sensor (Pi and Ti) Accurate intake pressure known realtime.

Potential for control on Pi but rarely done.

Advanced sensor (Pi, Pd, Ti, Tm, Vib)

Accurate determination of pump P, motor temperature, system vibration.

Complete toolkit to perform analysis and diagnosis of well and pump performance. Most Value

Table 1 – Levels of monitoring.

0

500

1000

1500

2000

2500

3000

3500

19:12 20:24 21:36 22:48 00:00 01:12 02:24 03:36

Pres

sure

(psi

a)

-10

40

90

140

190

240

Tem

p (D

eg F

) / C

urre

nt L

eaka

ge (m

A x

100

0) /

Vib

(g x

25)Discharge Pressure

Intake Pressure

Motor Oil Temp Intake Temp

Vibration

Point at which the pump should have been tripped.

Figure 3 – A preventable ESP failure. This pump could have been shutdown using intake pressure, discharge pressure or motor temperature parameters.

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PRES

0

2,000

4,000

6,000

8,000

10,000

12,0000 1,000 2,000 3,000 4,000

Pressure (psig)

True

Ver

tical

Dep

th (f

t TVD

)

From inflowMeasured dataRes. pressure

Figure 4 – A typical pressure response in an ESP produced well.

Above the pump

• Validate PVT • Watercut • Fluid specific gravity at pump discharge • Tubing GOR • Measure friction effect

Across the pump

• Validate Q, frequency, number stages • Measure viscosity and emulsion effects • Fluid specific gravity at the pump intake • % free gas at the pump intake • Obtain operating point for pump curve

Below the pump • Calculate bottomhole Pwf • Obtain PI or Pr

Table 2 – Summary of calculated / derived parameters that can be obtained from the gradient traverse plot.

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Figure 5 – An ESP pump curve showing the efficiency range of the pump in relation to the operating point.

Sensor Purchase Cost Days to Payout$20,000 2.00 $30,000 3.00 $40,000 4.00 $50,000 5.00 $60,000 6.00 $70,000 7.00 $80,000 8.00

Table 3 – Economics of sensor cost vs. time to payout based on a 1000 bopd and a price of $10/bbl.

0

2,000

4,000

6,000

8,000

10,000

12,000

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000Average pump flowrate (rb/day)

Tota

l hea

d (fe

et)

Head (50 Hz)Head (60 Hz)Head (70 Hz)Head (w/ CFs)Head at op. freq.Range (min/max)Op. Point

PRES

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,0000 500 1,000 1,500 2,000

Pressure (psig)

True

Ver

tical

Dep

th (f

t TVD

)

From inflowMeasured dataRes. pressure

Figure 6 – An ESP running in upthrust producing approximately 9435 bfpd.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

0 5,000 10,000 15,000 20,000Average pump flow rate (rb/day)

Tota

l hea

d (fe

et)

Head (50 Hz)Head (60 Hz)Head (70 Hz)Head (w / w ear)Head at op. freq.Range (min/max)Op. Point

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0

2,000

4,000

6,000

8,000

10,000

12,000

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000Average pump flowrate (rb/day)

Tota

l hea

d (fe

et)

Head (50 Hz)Head (60 Hz)Head (70 Hz)Head (w/ CFs)Head at op. freq.Range (min/max)Op. Point

PRES

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,0000 500 1,000 1,500 2,000 2,500

Pressure (psig)

True

Ver

tical

Dep

th (f

t TVD

)

From inflowMeasured dataRes. pressure

Figure 7 – The same well as previous example with a larger ESP producing approximately 12265 bfpd.

2600

2700

2800

2900

3000

3100

3200

30/01/01 00:00 01/02/01 00:00 03/02/01 00:00 05/02/01 00:00 07/02/01 00:00 09/02/01 00:00 11/02/01 00:00

Pres

sure

s (p

sia)

100

150

200

250

300

350

400

Tem

pera

ture

s (d

eg F

)

Discharge pressure

Intake pressure

Intake temperature

Motor oil temperature

Figure 8 – Example showing a well being produced using an ESP, the ESP is then switched off. The well continues to produce naturally, a pressure drop across the ESP can be observed. The arrows on the plot

represent points where the well was analysed.

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0

500

1,000

1,500

2,000

2,500

3,000

0 2,000 4,000 6,000 8,000 10,000 12,000Average pump flowrate (rb/day)

Tota

l hea

d (fe

et)

Head (50 Hz)Head (60 Hz)Head (70 Hz)Head (w/ CFs)Head at op. freq.Range (min/max)Op. Point

PRES

0

1,000

2,000

3,000

4,000

5,000

6,000

7,0000 500 1,000 1,500 2,000 2,500 3,000 3,500

Pressure (psig)

True

Ver

tical

Dep

th (f

t TVD

)

From inflowMeasured dataRes. pressure

Figure 9 – Analysis showing the ESP running normally. The well is producing 5750 bfpd.

PRES

0

1,000

2,000

3,000

4,000

5,000

6,000

7,0000 1,000 2,000 3,000 4,000

Pressure (psig)

True

Ver

tical

Dep

th (f

t TVD

)

From inflowMeasured dataRes. pressure

Figure 10 – Analysis showing the well producing naturally. A pressure drop of 54psi is observed across the shutdown ESP. This pressure drop accounts for a loss in production of 1000 bfpd.

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Figure 11 – An auto flow sub, which can be used above the ESP to eliminate pressure drop through ESP when the well is free flowing.

0

500

1,000

1,500

2,000

2,500

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000Average pump flowrate (rb/day)

Tota

l hea

d (fe

et)

Head (50 Hz)Head (60 Hz)Head (70 Hz)Head (w/ CFs)Head at op. freq.Range (min/max)Op. Point

PRES

0

1,000

2,000

3,000

4,000

5,000

6,000

7,0000 500 1,000 1,500 2,000 2,500 3,000 3,500

Pressure (psig)

True

Ver

tical

Dep

th (f

t TVD

)

From inflowMeasured dataRes. pressure

Figure 12 – Prediction showing the effect of a larger tubing diameter and larger ESP. The predicted production rate is 7900 bfpd.