GB2580445A

GB2580445A - Flow rate determination

Info

Publication number: GB2580445A
Application number: GB1907500.1A
Authority: GB
Inventors: Fjalestad Kjetil; Li Qin
Original assignee: Equinor Energy AS
Current assignee: Equinor Energy AS
Priority date: 2019-05-28
Filing date: 2019-05-28
Publication date: 2020-07-22
Also published as: GB201907500D0

Abstract

A method of determining a flow rate in a fluid conduit, such as in an artificially lifted hydrocarbon well, comprises: detecting or inferring the occurrence of a first change in temperature of a fluid at a first location 20 in said conduit; detecting the occurrence of a second change in temperature of said fluid, associated with said first change, at a second location 18 in said conduit downstream of said first location; determining a period of time between said first and second changes in temperature; obtaining a value of a volume of said conduit between said first location and said second location, and determining the flow rate of said fluid from said value of the volume and said period of time. The method may be used to determine flow rate in a production well. The first change in temperature may be created by heat generated by an electrical submersible pump (ESP) 6. Heating of the production fluid by the ESP may be by temporarily reducing the frequency of the ESP pump, or by using a wellhead choke to temporarily restrict the flow rate

Description

FLOW RATE DETERMINATION

Technical field

The invention relates to flow rate determination for example in artificial lifted wells.

Background

Electrical Submersible Pumps (ESPs) create artificial lift for oil wells to increase the fluid flow rate. The ESP is installed in the well tubing as seen in Figure 1. It is important to operate the ESP properly to avoid pump failures and to extend the pump life time.

The pressure over the pump and the flow rate are important in order to monitor the operating conditions of the pump. Figure 2 shows a diagram of pressure across the ESP plotted against flowrate, and indicating the region of normal operation. While the pressure over the pump is continuously measured with pressure sensors, the flow rate is usually calculated from a model. Since model input parameters like viscosity, which can change slowly or suddenly, will affect the calculated flow rate, the flow rate uncertainty is significant. Well conditions and operator interaction are the main reasons for ESP failures. Proper ESP operation is challenging. Fluid viscosity, well productivity, gas fraction at ESP intake (inflow conditions), and available electric power may change, and during ESP operation only some parameters are considered for safe and optimal production. Offshore oil fields may have ESPs in all the producing wells, and operation of one pump can affect the operating conditions of the ESPs in other wells.

Usually, wells are required to be tested regularly. Normally a dedicated test separator is used to measure the flow rate of each produced phase (oil, gas and water). For fields without a test separator, deduction testing is an alternative. Deduction testing is normally done by shutting in a well and determining the flow rate from the reduced overall production rate. The tested well may also be routed from one separation train to the other, thus the increased rate on one train and the reduced rate on the other train indicates the flow rate of the well.

Deduction well testing is an expensive process due to production loss and the limited operational freedom during the test. Also, the test does not always provide sufficient accuracy of the flow rate. For high water cut (i.e. low oil rate) well testing is nearly impossible. Many wells have high water cut, which increases over time.

Summary of the invention

Aspects of the invention provide methods of determining the flow rate in a fluid conduit, as set out in the accompanying claims.

Preferred embodiments of the invention are described below with reference to the accompanying drawings.

Brief description of the drawings

Figure 1 shows a schematic diagram of an artificial lifted well; Figure 2 shows a graph illustrating the normal operation window of an ESP; Figure 3 shows a schematic diagram of an artificial lifted well in which the flow rate is determined by a method according to an embodiment; Figure 4a shows the relative error in flow rate plotted against the error in the determined transportation time; Figure 4b shows a zoomed in graph of the relative error in flow rate plotted against the error in the determined transportation time; Figure 5 shows a schematic diagram of a test flow loop used; Figure 6 is a graph showing the flow rate determined according to an embodiment plotted against a reference flow rate; Figure 7a is a graph of well parameters plotted against time which Illustrates an embodiment in which the frequency of the ESP is changed; Figure 7b is a simplified graph of Figure 7a showing the ESP frequency and well head temperature plotted against time; Figure 8a is a graph of well parameters plotted against time which Illustrates an embodiment in which natural inversion of the flow regime is used to determine the flow rate; Figure 8b is simplified graph of Figure 8a showing the ESP frequency, ESP inlet pressure and well head temperature plotted against time; Figure 9 is a flow diagram illustrating the steps of a method according to an embodiment; and Figure 10 is a graph of well parameters plotted against time which Illustrates an embodiment in which natural inversion of the flow regime is used to determine the flow rate.

Detailed description

Described herein are methods of determining the flow rate in a fluid conduit by detecting or inferring the occurrence of a change in temperature of fluid at a first location in the conduit and measuring the temperature at a second location downstream to determine the time period for the fluid to travel from the first to the second location. If the volume of the conduit between the two locations is known, then the volumetric flow rate can be calculated by dividing that volume by the time period. The method may be applied to flowlines, export pipes and production wells. For example, in a flowline comprising a pump, a change in temperature at the outlet of the pump can be inferred from a change in power or frequency of the pump. Alternatively, the conduit may be temporarily choked (closed or partly closed) downstream of the pump to cause the fluid at the pump to heat up.

In an artificial lifted production well, the flow rate is important for proper allocation, reservoir management, ESP operation and production optimisation. For fields with long transportation lines and without a test separator, deduction tests may be used, but the measured oil rates have a high uncertainty. Wells with a high water cut (e.g. 80%), may be impossible to test using deduction testing.

Described herein is an Artificial Lifted Well Testing (ALWT) method, which can enable testing of wells with long transportation lines and/or high water cut. The described method may be particularly useful for such wells, where deduction testing is unreliable, but can be used with any artificial lifted well. The method is based on ESP excitation, which will affect the pumped fluid temperature. The transportation time until the fluid temperature variation is detected downstream can be determined and used together with the well volume to calculate the produced well flow rate. The flow rate and the water cut can then be used to calculate the produced oil rate.

According to an embodiment of the method, the ESP operation is manually changed by changing the frequency of the ESP. The frequency is changed by an amount of 1% to 25% of the original frequency for a short period of time (e.g. around 2 to 5minutes). For example, the frequency may be decreased as low as allowed by well conditions for a period of 3 to 5 minutes. Generally, 40% to 50%, but sometimes up to 80%, of the electric power to the ESP motor is converted to heat (and the remaining power contributes to the hydraulic lift), and variation of the supplied power therefore influences the temperature of the lifted fluid. That is, a change in temperature of the fluid at the outlet of the ESP can be inferred from a change in ESP frequency. The temperature variation is then detected a distance downstream of the pump, for example using a temperature gauge located in the well head. The distance from the ESP to the well head is typically over 1000 meters and for example between 2000 m and 4000 m. The time period between the ESP excitation (i.e. the change in frequency) and the temperature response is determined (for example from a graph plotting the temperature at the well head and the ESP power over time). This time period can be referred to as the transportation time. The flow rate is then determined by dividing the well volume (in this case the volume of the production string) between the ESP outlet/discharge and the downstream point at which the temperature is measured by the determined time period.

Figure 3 shows a schematic diagram of a hydrocarbon production system 2 in which the method may be used. Production tubing 4 with an ESP 6 having a variable speed drive (VSD) is located in a well 8. On the toe-side of the ESP 6, packers 10 provide zonal isolation and control of different production zones in the formation 12. Hydrocarbons (not shown) enter the production tubing from the surrounding formation 12 and flow towards the heel (upwards) due to the reservoir pressure. The ESP 6 provides additional lift by increasing the pressure. At the surface 14, the well head 16 is provided with a temperature gauge 18 for measuring the temperature of the production fluids. In order to determine the flow rate, the volume V of the production tubing 4 between the head 20 of the ESP 6 and the temperature gauge 18 must be known. Two graphs 30 and 32 show the frequency of the ESP 6 and the temperature measured at the well head 16 plotted over time. The frequency of the ESP 6 is decreased from 60 Hz to 55 Hz (about 8%) at time 2 h. There is an immediate drop in temperature due to the reduced flow rate, which allows the fluid to cool for longer on the way up through the production tubing. The frequency is reset to 60 Hz after a short time and the temperature increases towards its original steady state value of 80 C. At time 3 h, the fluid that was located at the ESP 6 at the time when the ESP 6 was operating at lower frequency reaches the temperature gauge 18, causing a brief spike in temperature (when the power is reduced, the ratio between heat and lift increases, which increases the temperature due to the lower flow rate). The time period At between the change in frequency and the temperature response is 3 h -2 h = 1 h, and the volumetric flow rate can be calculated from the volume Vof the production tubing 4 between the ESP Band temperature gauge 18. The frequency of the ESP 6 can also be increased to produce a temperature response.

In another embodiment, instead of changing the frequency of the ESP, the ESP may be excited in other ways. In particular, a choke at the well head may be used for a short period of time to restrict fluid flow, thereby temporarily reducing the flow rate. The choke position can be expressed as a percentage of the fluid outlet that is covered, where 0% represents a completely closed/blocked outlet and 100% represents a completely open outlet. This has a similar effect on the temperature of the fluid as the decrease in ESP frequency described above. If an automatically controlled ESP is used, which is programmed to produce a constant flow rate, then choking at the well head will cause an increase in ESP frequency. It is recommended to choke (hard, e.g. 10% opening, or more than 10 bar pressure increase) for 2 to 5 minutes or 3 to 5 minutes at the well head. Dynamic simulations have shown that choking is efficient for the ALWT method. In addition, the ALWT method may give qualitative indication of water cut development, as a higher water cut reduces the temperature variation. However, ALWT may not be suitable to determine water cut accurately.

The ESP excitation and/or flow variations may occur due to natural phenomena in the well, such as an inversion of the flow regime. The ESP efficiency and the flow rate are significantly affected by the inversion, causing a measureable temperature change downstream. To utilise variations due to flow inversion is also recommended since the flow rate will change a lot in a very short time. Under such conditions it is important to detect flow variations to enable proper flow rate allocation.

In general, the ALWT method may comprise the following ordered steps: Step 1: Flow rate variation of ESP lifted well. For example, natural variation, well head choking, ESP frequency variation, well head choking with automatic ESP control.

Step 2: Observe temperature response at the well head and determine the time (At) taken from the variation of step 1 to the temperature response.

Step 3: Determine well flow rate from volume and time. The volume is the well volume between the ESP and the temperature gauge (generally located at the well head). The flow rate can be written as

V

well = At * wherein a.. is the fluid flow rate of the well, V is the volume of the well between the ESP and the temperature gauge, and At is the time between the excitation and the temperature response. ;Step 4: Determine the oil rate (clod) from the volume flow rate and water cut by 100-WC qwell * Wherein q0 is the oil flow rate and WC is the water cut (expressed as a percentage value).

The results from this well test will be affected by fluid properties, flow regime, pipe dimension and temperature sensing (accuracy and transient response). It is important to ensure accurate temperature measurements and to record data with high resolution in the production data base.

Each of the steps is described in more detail below: Step 1: the electric power, Pp"nnp, supplied to the ESP will provide hydraulic lift, APFlud,Mechanical, and give heat, AO --Fluid,Heat, to the pumped fluid as expressed in equation ( 1). Since the ambient temperature of the ESP in the formation is close to the fluid temperature, the heat loss, AC)Lass, can be neglected. From equation ( 2) it can be seen that the volume flow rate, q, and the pressure increase, Ap, over the pump is related to the hydraulic lift power. Sometimes fluid variations will induce changes in pump efficiency, ii, as well as volume rate and pressures. Such natural variations may be utilised to determine transportation time. Since such variations lead to new pump conditions, these are very useful to determine the well rate. Planned tests, as opposed to natural variations, are excited by either well head choking or ESP frequency variations. The excitation should be short to minimize direct flow rate impact on the well head temperature. Preferred embodiments of the ALWT method comprise choking in a well with an ESP that has automatic inlet pressure control. For such cases the flow will remain constant during the choking, and the power variation will be transformed to fluid temperature changes.

Pump = APPluhi ha ± A. Q flea, + A Q Los, (1) TIPPump = APFluid,Mechanical = AAP (2) Step 2: the response in the well head temperature should be measured and recorded accurately. As long as the excitation in Step 1 is sufficiently large, and no other flow variations for the tested well have a high influence on the well head temperature at that time, the excitation temperature response can be detected. The measured well head temperature can be recorded in the production database with high resolution. The excited variable (Choke position and/or ESP frequency) should also be recorded accurately, but it is mainly the well head temperature measurement that influences flow rate errors. Since the excitation has two changes (e.g. reduction and then step back to the original value), two temperature responses will normally be observed. For higher accuracy in the determined transportation time, both times can be determined and compared. Equal times from drop to rise at the ESP and at the well head gauge indicate a high accuracy, and for other cases the average time between the two events can be used.

Step 3: Besides the transportation time, the well volume V should be determined as accurately as possible. Most wells have accurate data of the completion string design (including well volume) stored in a database. The volume between the upper completion and the position of the well head temperature gauge should also be determined. The result may vary for different flow regimes and may be influenced by gas which will have different density and mass fraction depending on actual pressure and temperature. Detailed flow and PVT models can be applied to improve method accuracy.

V

CIFfual 47 hl Step 4: Compensation with water cut to determine the oil rate ( 3) qou = 100-WC [TN ( 4) qFluid The ALWT method will not be more accurate than the transportation time reading. If correct well volume is assumed, the recorded time will influence the relative flow rate error, Oi erron according to equation ( 5): ALTW Real AtReal ( 5) tlError = qReat atALTW where a ALTW is the flow rate determined with the ALTVV method, el real is the real/actual flow rate, AtAnw is the time measured between ESP excitation and the downstream temperature response, and Atreal is the real/actual time between those events. Wells in some fields may have typical transportation times from 30 to 60 minutes. Low producing wells could have up to 2 hours transportation time. The relative error determined from equation ( 5) for such cases, assuming a sampling time of 1 minute, is plotted in Figures 4a and 4b.

Figures 4a and 4b show the relative error in flow rate plotted against the absolute error in time for three different transportation times. Figure 4b is shows the same plots as Figure 4a but for a narrower range (i.e. zoomed in). The transportation time should be determined precisely to find the flow rate accurately.

Table 1 summarises some of the results from equation ( 5), and shows the maximum and minimum errors in the determined time period At to stay within ±1%, ±2% and ±5% flow rate error. From Table 1 it can be seen that for wells with 30 minutes transportation time, this time should be identified with less than 18 seconds error to ensure a relative flow rate error within ±1%. Based on this analysis, two conclusions can be made: 1) the method is most suited for wells with (relatively) long transportation times, and 2) the well head temperature should be accurately measured and recorded with high resolution.

Table 1

Accuracy 30 min ransport 60 min transport 120 min transport Min Max Min Max Min Max AtError [5] AtError [5] AtError [5] AtError [5] AtError [5] AtError [s] ± 1 % -17.8 18.2 -35.6 36.4 -71.2 72.8 ± 2 % -35.3 36.7 -70.6 73.4 -141.2 146.8 ± 5 % -85.8 94.7 -171.6 189.4 -343.2 378.8 The ALWT method has been tested in a multiphase flow loop, by exciting the ESP frequency or a choke at the outlet of the pipe. The average absolute relative error from the reference flow rate was less than 1. 5% even with up to 20% gas fraction in the pumped fluid. The method has also been successfully applied and evaluated on four wells.

It is recommended to apply ALWT on ESP lifted wells since it enables efficient well testing to determine the produced flow rate. With this method several wells can be tested simultaneously, and the test is independent of variations in other wells, transportation flow lines and top side facilities. ALWT will also give minimal production loss (which is not the case for deduction testing when the tested well is shut in for hours) and can be applied regularly (e.g. daily). For wells with high water cut, low flow rate and/or long transport pipe, ALWT may be the only realistic test method.

As an alternative to deduction testing, the Artificial Lifted Well Testing method can be applied to all ESP lifted wells. The associated production loss is negligible, and the impact from variations topside or in other wells is small. While traditional deduction testing may focus the main produced phase (i.e. oil rate), ALWT determines the total fluid volume flow rate from the well. For ESP surveillance and monitoring, and also for reservoir management, the total fluid rate is very important.

In traditional well testing, only the oil rate is determined, and the accuracy is relatively low. For wells with high water cut (i.e. low oil rate) the ALWT method could be more accurate even if the transportation time is not accurately identified -especially for the well liquid rate. Note that for wells with long (multiphase) transportation lines up to the processing units, traditional well testing can take a very long time, in order to ensure stable conditions in the pipe lines. This applies to both test separator and deduction testing. The ALWT method is independent of downstream facilities, and is therefore easy to perform and enables testing of wells that are difficult or impossible to test with traditional methods.

The ALWT method has been tested in a multiphase flow loop, by exciting the ESP frequency or a choke at the outlet of the pipe. The pipe outlet in the flow loop corresponds to the well head in in an actual well. The flow rates determined using the method were well aligned with the reference flow rates. The average absolute relative error from reference flow rate was less than 1. 5 % even with up to 20 % gas fraction in the pumped fluid.

The layout of the multiphase flow loop is shown in Figure 5. The ESP in the test loop is a centrifugal pump with 84 stages. The ESP is mounted horizontally, and the motor is outside the pipe. Gas and water can be mixed with the oil upstream of the ESP. The flow rate of each phase that is mixed upstream of the ESP was individually measured by accurate Coriolis flow meters for reliable reference flow rates.

The ALWT method was tested several times in the flow loop, with different types of excitation. The most successful test results were obtained with the ESP in automatic mode (controlling the intake pressure) and choke at the pipe outlet for a short time (around 1 minute). Variation of the ESP frequency (for a short period, around 1 minute) was also tested in the flow loop and gave a visible temperature response at the pipe outlet.

The results from 28 tests in the flow loop are summarised in Table 2. Seven tests were performed with ESP frequency variations, and 21 with choking. For half of the tests, both oil and gas were fed into the ESP (Gas Volume Fraction, GVF, in the range from 10% to 20%), and the other tests were conducted with oil. Table 2 shows both the full scale (FS) absolute error and the relative (rel.) absolute error.

Table 2

Flow rate Abs. error FS abs. error Rel. abs. error m3/11 m3/11 Mean 12.724 0.206 1.17 % 1.56% Median 14.064 0.172 0.98 % 1.31% Max 17.627 0.767 4.35% 4.40% From the start of the test campaign, the 3" loop was used as transportation pipe up to the temperature gauge, and later also the 2" loop was used in series with the 3" loop.

The volume for the first testing was determined to be 0. 894 m3, and the full volume 1. 325 m3.

Figure 6 shows a graph of the determined flow rate using embodiments of the ALWT method in the test loop plotted against the reference flow rate (from Coriolis flow meters). There is good agreement between the determined flow rate and the reference flow rate.

The ALWT method was also tested on (actual) subsea wells. Several flow variations with detectable well head temperature responses were recorded.

Figure 7a shows a graph 40 of data collected from a well W1 over time. The graph 40 plots ESP frequency 42, ESP inlet/intake pressure 44, ESP intake temperature 46, well head temperature (WHT) 48, ESP motor current 50, and liquid rate at standard conditions 52 (normally at atmospheric pressure and 15 PC). A first vertical line 54 indicates the time at which the ESP is excited by decreasing its frequency 42 from about 57 kHz to about 56 kHz. A second vertical line 56 indicates the time at which the frequency 42 is restored back to 57 kHz. A third vertical line 58 indicates the time at which the WHT 48 starts to increase due to the earlier drop in frequency 42, and a fourth vertical line 60 indicates the time at which the WHT 48 starts to decrease again.

The volume of W1 (between the ESP outlet and the well head temperature gauge) was 33 m3 (obtained from completion string design data of W1) and the time period between the drop in frequency 42 and the corresponding increase in WHT 48 was 3. 7 hours. Hence, the calculated flow rate for this test was 33/3. 7 = 8. 9 rn3h1 or 214 m3 per day. The water cut was determined to be 42%, giving an oil rate of about 124 m3 per day.

Figure 7b shows a schematic representation of Figure 7a, with only the ESP frequency 42 and WHT 48 plotted against time. The time period At between the drop in ESP frequency at t1 and the increase in WHT at t2 is indicated.

Figure 8a shows a graph 40 of data collected from another well W2 over time. The graph 40 plots well head choke position 62, ESP break horse power to pump W2 64, liquid rate at standard conditions 52, ESP frequency 42, ESP discharge temperature 66, well head temperature (WHT) 48, and ESP intake pressure 44. Three separate tests using the ALWT method were conducted to independently determine the flow rate at different times. In all three tests, the observed changes in well conditions resulted from naturally occurring inversion of the fluid flow. At a first time 68 an inversion of the fluid flow occurs, causing a drop in the ESP intake pressure 44. This causes the temperature 66 of the ESP discharge fluid to decrease. The cooler fluid reaches the well head at a second time 70, causing the measured WHT 48 to drop. At a third time 72 another inversion occurs, which causes a sharp rise in the ESP intake pressure 44. The ESP discharge temperature 66 also increases and the warmer fluid reaches the well head at a fourth time 74, as seen by the increasing WHT 48 at this time. At a fifth time 76 another inversion occurs and the ESP intake pressure 44 drops. A corresponding drop in the measured WHT 48 is identified at a sixth time 78. The frequency 42 of the ESP can also change at the time of the inversion due to changes in the motor load (e.g. because of internal control in the speed drive for the motor).

W2 was equipped with a temperature gauge at the ESP outlet to measure the ESP discharge temperature 66. The ESP discharge temperature can be used to determine the flow rate from the energy balance over the ESP. This provided an additional measurement of the flow rate for comparison with the ALWT method.

Figure 8b shows a schematic representation of Figure 8a, with only the ESP intake pressure 44, ESP frequency 42 and WHT 48 plotted against time. The time periods At between t1 and t2, between -Ea and ta and between t6 and t6 were used together with the well volume of W2 to calculate the flow rate at three different times. The well volume from the ESP discharge to the well head was obtained from the completion string design data of W2. The determined flow rates were 1146 m3 per day, 969 m3 per day and 1060 m3 per day respectively. For comparison, the corresponding flow rates calculated from the energy balance over the ESP were 1158 m3 per day, 990 rn3 per day and 1100 rn3 per day respectively, which are very close to the values determined with the ALWT method. Figures 8a and 8b exemplify how the described method can be used to determine the flow rate without having to manually excite the ESP, but instead by observing and recording changes in the well condition (e.g. ESP intake pressure) due to naturally occurring phenomena (e.g. inversion).

Figure 9 is a flow diagram illustrating the steps of an embodiment of the ALWT method for determining the flow rate in an artificially lifted well. The method comprises determining a first change in temperature of production fluid at an outlet of an Electrical Submersible Pump (ESP) in said well, detecting a second change in temperature of said fluid associated with said first change at a location downstream of said ESP, and determining a period of time between said first and second change in temperature. The method further comprises obtaining a value of a volume of said well between said outlet of the ESP and said location downstream of the ESP, and determining the flow rate of said fluid from said value of the volume and said period of time.

Although the above embodiments describe how the change in temperature at the ESP outlet can be inferred from the ESP frequency, the well head choke position and/or the ESP intake pressure, other well parameters, such as the ESP motor current and ESP break horse power to pump, may also be used in some to infer such a temperature change in the production fluid. Multiple well parameters may be used simultaneously to determine a change in temperature of the production fluid at the ESP outlet. This can reduce the uncertainty in the time at which the temperature of the fluid at the ESP outlet changes.

Figure 10 shows a graph 40 in the change of three separate monitored well parameters are used to infer a temperature change at the ESP outlet due to flow inversion. At a first point in time 80 the consumed power of the ESP increases 82a, the WHT decreases 82b, and the ESP intake pressure increases 82c due to an inversion of the flow regime, which decreases the flow rate. The reduced flow rate causes an increase in the WHT 84 at a second point in time 86. The difference between the two points in time and the well volume can then be used to calculate the flow rate. At a third point in time 88 another inversion occurs, which increases the flow rate and causes the consumed power of the ESP to decreases 90a, the WHT to increases 90b, and the ESP intake pressure to decreases 90c. The increased flow rate causes a decrease in the WHT 92 at a fourth point in time 94. The difference between the third and fourth points in time can then be used to calculate the flow rate.

A similar method may be used to determine the flow rate in a gas lifted well, in which gas is injected at a point in the well at a similar depth to that of the ESP in an artificially lifted well. Gas can be injected continuously into the production well. The injected gas mixes with the production fluids and decreases the density. The first change in temperature can then be inferred from a change in the gas injection (increased or decreased gas injection rate), which affects the temperature of the production fluid at the injection point. Alternatively, a well head choke can be used while keeping a constant gas injection rate. The formula for calculating the flow rate is the same as for the ALWT method used on a well with an ESP. That is, infer or detect a first change in temperature at a first location (at the gas injection point) and measure the time period until a change in temperature is measured at a second location downstream (typically at the well head), and then divide the volume of the well between the two locations by that period of time.

While specific embodiments of the invention have been described above, it will be appreciated that the invention may be practiced otherwise than as described. The descriptions above are intended to be illustrative, not limiting. It will be apparent to one skilled in the art that modifications may be made to the invention as described without departing from the scope of the claims set out below.

Each feature disclosed or illustrated in the present specification may be incorporated in the invention, whether alone or in any appropriate combination with any other feature disclosed or illustrated herein.

Claims

CLAIMS: 1. A method of determining a flow rate in a fluid conduit, the method comprising: detecting or inferring the occurrence of a first change in temperature of a fluid at a first location in said conduit; detecting the occurrence of a second change in temperature of said fluid, associated with said first change, at a second location in said conduit downstream of said first location; determining a period of time between said first and second changes in temperature; obtaining a value of a volume of said conduit between said first location and said second location; and determining the flow rate of said fluid from said value of the volume and said period of time.
2. A method according to claim 1, wherein said fluid conduit is a production string in a production well and wherein said fluid is production fluid.
3. A method according to claim 2, wherein said production well is an artificially lifted well comprising an Electrical Submersible Pump (ESP), and wherein said first location is at an outlet of said ESP.
4. A method according to claim 3, further comprising changing a frequency of said ESP to cause said first change in temperature, wherein said step of detecting or inferring said first change in temperature comprises inferring said first change in temperature from the change in frequency.
5. A method according to claim 4, wherein said frequency is changed by an amount between 1% and 25% of an initial frequency of said ESP for a period of time in the range of 2 min to 5 min.
6. A method according to claim 4, wherein said frequency is changed for a period of time greater than one hour.
7. A method according to claim 3, further comprising changing a choke position of a choke at a well head of said well to cause said first change in temperature, wherein said step of detecting or inferring said first change in temperature comprises inferring said first change in temperature from said change in said choke position.
8. A method according to claim 7, wherein said ESP has automatic control of ESP intake pressure.
9. A method according to claim 7 or 8, wherein said choke position is changed so that the opening of a fluid outlet is changed by an amount in the range of 5% to 50% of the total opening for a period of time in the range of 0. 5 min to 5 min.
10. A method according to claim 3, wherein said well comprises a valve located upstream of said ESP, the method further comprising opening or closing said valve to cause said first change in temperature.
11. A method according to claim 3, further comprising detecting an inversion of a flow regime at said ESP, wherein said step of detecting or inferring said first change in temperature comprises inferring said first change in temperature from said inversion.
12. A method according to claim 11, further comprising continuously monitoring an ESP intake pressure, wherein said step of detecting said inversion comprises detecting a change in said ESP intake pressure.
13. A method according to claim 3, further comprising measuring a temperature of said fluid at said outlet of the ESP to determine said first change in temperature.
14. A method according to any one of claims 3 to 13, wherein said second change in temperature is detected by measuring a temperature of said production fluid at the well head of said well.
15. A method according to any one of claims 3 to 14, further comprising estimating a water cut of said production fluid from said second change in temperature.
16. A method according to any one of claims 3 to 15, further comprising: displaying at least one well parameter over time; displaying a temperature over time of said production fluid at said location downstream of the ESP; locating a first point in time where said at least one parameter changes so that said first change in temperature of said production fluid at said outlet of the ESP can be inferred; and locating a second point in time where said second change in temperature at said location downstream of the ESP occurs, wherein said period of time between said first and second changes in temperature is the difference between said first and second points in time.
17. A method according to claim 16, wherein said at least one well parameter comprises one or more of ESP intake pressure, ESP frequency, well head choke position, ESP discharge pressure, ESP motor current, and ESP break horse power to pump.
18. A method according to claim 2, wherein said production well is a gas lifted well, and wherein said first location is at a gas injection point in said well.
19. A method according to claim 18, further comprising changing a gas injection rate, wherein said step of detecting or inferring said first change in temperature comprises inferring said first change in temperature from the change in injection rate.
20. A method according to claim 18, further comprising changing a choke position of a choke at a well head of said well to cause said first change in temperature, wherein said step of detecting or inferring said first change in temperature comprises inferring said first change in temperature from said change in said choke position.
21. A method according to claim 1, wherein said conduit is a flowline or an export pipe comprising a pump, and wherein sad first location is at an outlet of said pump.
22. A method according to claim 21, further comprising changing a frequency of said pump to cause said first change in temperature, wherein said step of detecting or inferring said first change in temperature comprises inferring said first change in temperature from the change in frequency.
23. A method according to claim 21, further comprising changing a choke position of a choke of said fluid conduit at a position downstream of said first location to cause said first change in temperature, wherein said step of detecting or inferring said first change in temperature comprises inferring said first change in temperature from said change in said choke position.