Submersible pump monitoring

Abstract

In order to address the above noted problems, embodiments of the present invention use distributed acoustic sensing to monitor the fluid level in an ESP activated well so as to monitor the condition and performance of the ESP. Embodiments of the invention use the ESP as an acoustic source in order to monitor the annulus fluid level within the well and to monitor the frequency of the ESP. Additionally, embodiments of the present invention may use distributed acoustic sensing to monitor the flow rates of the production fluid above and below the ESP to determine the pump's efficiency. In particular, some embodiments utilize one or more optical fibers to measure the acoustic waves generated by the ESP, wherein the fiber cabling has already been deployed along the length of the well. As such, the present invention is a non-invasive, in-situ method for monitoring the condition and performance of an ESP.

Claims

1. A method of in-well fluid level detection around an in-well submersible pump using an optical fiber distributed acoustic sensor having an optical fiber deployed in-well, the method comprising: a) measuring a propagation of acoustic waves within fluid in a vicinity of the submersible pump using the optical fiber distributed acoustic sensor, wherein the acoustic waves are generated by the submersible pump when in operation, the speed of sound of the acoustic waves being measured along a length of the optical fiber within the vicinity of the submersible pump to measure the propagation therefrom; and b) detecting an in-well fluid level by determining, in dependence on the measurements by the optical fiber distributed acoustic sensor of the propagation of the acoustic waves generated by the submersible pump, a location of a fluid interface within the well with respect to the submersible pump to thereby further determine whether the submersible pump is submerged in the fluid, wherein determining the location of the fluid interface in the well includes detecting a change in the speed of sound measurements, wherein a spatially abrupt change in the speed of sound measurements as a result of weak acoustic coupling is indicative of acoustic energy propagating above the fluid interface.

2. A method according to claim 1, wherein measuring the propagation of acoustic waves includes detecting one or more reflections of an acoustic wave.

3. A method according to claim 1, wherein determining the location of the fluid interface in the well comprises measuring the propagation of acoustic waves from a known location of the submersible pump to the fluid interface to determine the distance from the known location to the interface.

4. A method according to claim 1, wherein the propagation of acoustic waves generated by the submersible pump are measured below and/or above the pump.

5. A method according to claim 1, wherein the optical fibre distributed acoustic sensor is further arranged to measure one or more operating frequencies of the submersible pump.

6. A method according to claim 5, wherein the operating frequencies are measured during start-up and/or the operation of the submersible pump.

7. A method according to claim 5, wherein the optical distributed acoustic sensor detects any changes in the operating frequencies.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) Further features and advantages of the present invention will become apparent from the following description of an embodiment thereof, presented by way of example only, and by reference to the drawings, wherein like reference numerals refer to like parts, and wherein:

(2) FIG. 1 is a cross-sectional view illustrating a typical in-well deployment of an ESP and optical fibre distributed acoustic sensor in accordance with an embodiment of the present invention;

(3) FIG. 2 is a graph plotting the frequencies of acoustic waves generated by an ESP, as measured by an optical fibre distributed acoustic sensor;

(4) FIG. 3a is graph showing the measured acoustic signal in accordance with an embodiment of the present invention when the ESP is turned off;

(5) FIG. 3b is graph showing the measured acoustic signal in accordance with an embodiment of the present invention when the ESP is turned on;

(6) FIG. 4 is a flow diagram illustrating the typical steps employed in one aspect of an embodiment of the present invention;

(7) FIG. 5 is a flow diagram illustrating the typical steps employed in a further aspect of an embodiment of the present invention;

(8) FIG. 6 is a drawing of an example space-time plot of the data collected by a DAS in a deployment like that of FIG. 1; and

(9) FIG. 7 is a drawing of a 2D Fourier transform (k- plot) of the space-time plot of FIG. 6;

(10) FIG. 8 is a graph showing upwards and downwards speed of sounds in a pipe, (top) together with calculated Doppler shifts (bottom) that provide fluid velocity measurements;

(11) FIG. 9 is a flow diagram illustrating the typical steps employed in a further aspect of an embodiment of the present invention.

DESCRIPTION OF THE EMBODIMENTS

(12) In a particular embodiment of the invention, described here in order to provide an example of a preferred implementation of the present invention, an optical fibre distributed acoustic sensor is provided along an ESP activated well in order to detect the propagation of acoustic waves generated by the ESP, and thus monitor the annulus fluid level of the well, as will be described. In use, as known in the art, an ESP is submerged into the production fluid and used to increase the flow rate of production fluids. The ESP decreases the pressure at the bottom of the well by increasing the drawdown in order to artificially lift the production fluid from its reservoir to the surface.

(13) FIG. 1 illustrates a typical deployment scenario for embodiments of the present invention. Here, a wellbore 3a has been drilled down into gasoline producing rock 5, and a casing 3b installed therein. During completion of the wellbore 3a, a submersible pump, such as an electrical submersible pump (ESP) 2 is inserted into the casing 3b, and moved along the casing 3b to its intended position, for example within or above the intended production zone of the well 3a. The ESP 2 is deployed within the casing 3b in order to increase the flow rate of the oil, so as to help lift the oil to the surface. The casing 3b is provided running along its outer surface with one or more optical fibres 1a as well as usually other cabling, provided for signalling, sensing or control purposes. A distributed acoustic sensing (DAS) system 1b is provided, connected to the one or more optical fibres 1a, and which may operate in a distributed acoustic sensing mode as known in the art to detect the propagation of acoustic waves generated by the ESP 2, or by other acoustic sources, within the casing 3b. The DAS is typically able to record sound incident on the cable at between 1 m and 5 m native resolution along the whole length of the cable, at frequencies up to around 100 kHz. Next generation DAS systems will likely have higher spatial and frequency resolutions, and hence the figures mentioned here are by way of example only.

(14) Further by way of example, the DAS system may be a Silixa iDAS system, the details of operation of which are available at the URL http://www.silixa.com/technology/idas/, and which is also described in our earlier patent application WO2010/0136809, any details of which that are necessary for understanding the present invention being incorporated herein by reference.

(15) A first embodiment of the invention will now be described with respect to FIG. 4, wherein an optical fiber based DAS system is used to monitor the operation of an ESP, via condition monitoring of the noise that the ESP makes during operation. For example, the amplitude and frequency of the sound generated by an ESP is a function of the condition and power output of the ESP. By monitoring the amplitude and frequency (or more accurately frequencies) of the ESP during operation, the condition of the ESP can be ascertained, and an operator may begin to tell, particularly from changes in the frequencies produced, as to whether an ESP is beginning to fail.

(16) FIG. 4 provides a flow diagram illustrating an example sequence of operations in the first embodiment of the present invention, given the equipment described above. In particular, at s.40 monitoring of the ESP using the distributed acoustic sensor system 1b is commenced. During the monitoring period the distributed acoustic sensing system is able to monitor the operating frequencies of the ESP 2 during start-up, as in s.41, and during steady state operation, as in s.42, the results of which are demonstrated by way of example in FIG. 2. Upon start-up, the ESP 2 generates start-up frequencies 6 that increase rapidly, and then stabilize as the ESP commences operation. As shown, the operating frequencies 7 stay at a steady frequency or frequencies for the duration that the ESP is operating normally. The distributed acoustic sensing is able to determine the ESP's fundamental frequency at s.43, that is, the lowest frequency at which the ESP operates, and measure the magnitude of different operating frequencies 7 at different pump rates at s.44. Continuous monitoring of the operation of the ESP over extended periods of time is possible, as shown by s.45.

(17) From this diagnostic monitoring the distributed acoustic sensing system 1b is able to determine the condition and the performance of the ESP. Firstly, any changes or irregularities in the ESP operation frequencies 7 can be identified and used to help to determine any defects or problems with the ESP. Secondly, the ESP frequency is directly proportional to its pump rate, and so the ESP pump rates may be controlled, via monitoring of the operating frequencies 7, such that the ESP 2 generates optimal reservoir drawdown, that is to say, optimal production rate is achieved.

(18) A second embodiment of the invention will be described with respect to FIG. 5. The second embodiment relates to monitoring the annulus fluid level in the vicinity of an ESP, using an optical fiber DAS. In this respect, in order to protect an ESP it is important that there is liquid around the ESP during its operation. Within the second embodiment the DAS system is used to monitor liquid levels around the ESP.

(19) FIG. 5 provides a flow diagram illustrating the sequence of operations in the present embodiment, given the equipment described above. In particular, at s.50 the distributed acoustic sensor system 1b is operated in order to monitor the annulus fluid level 4 within the casing 3b, as shown in FIG. 1. To monitor the annulus fluid level 4, in one embodiment the ESP 2 is used as an acoustic source and the distributed acoustic sensor system used to measure the acoustic wave propagations above and below the ESP 2, as given in s.51 and s.52, and to identify any acoustic signal reflections from fluid interfaces 4 within the casing 3b. In other embodiments, however, and particularly when the ESP is not operating, other acoustic sources may be used as the acoustic illumination that is detected by the DAS. For example, acoustic energy from external sources can be coupled into the well, and used as acoustic illumination to determine the fluid levels. Such external acoustic energy may be naturally occurring, or result from external events such as seismic surveying. Alternatively, sound sources from within the well itself might be used. For example, where fluid is flowing within the pipe, flow noise from the fluid might be used (if loud enough), or alternatively synthetic noise sources such as clickers driven by fluid flow, or electrically driven sounders may be used to provide a sound source. Whichever sound source is used, it needs to be loud enough in the vicinity of the ESP so that it is detectable by the DAS, so that the DAS can determine the annulus fluid level around the ESP.

(20) In more detail, the distributed acoustic sensor system 1b measures any acoustic wave propagations within the casing 3b when the ESP 2 is turned off, wherein the acoustic signal is measured both above and below the pump. As shown in FIG. 3a, in this example there are no propagating acoustic signals detected within the casing. Detection of any acoustic signals at this point may indicate that there is a problem with either the ESP 2 or the well as a whole, for example, an external disturbance. The ESP 2 may then be turned on, and at s.52 the distributed acoustic sensing system 1b is able to measure acoustic wave propagations generated by the ESP 2, above and below the ESP 2, as before. FIG. 3b provides an example of such measurements. Above the pump, acoustic waves are seen to propagate up the well to a fluid interface 4, and then back down the well 9a, reflected from the interface 4. Below the pump, acoustic waves are seen to propagate down the well 9b. At s.53, the limit of acoustic wave propagation 8 may be determined, that is, the height at which acoustic waves above the pump 9a propagating up the well are reflected back down from the fluid interface. This limit 8 is due to a reflection effect, wherein the acoustic waves reflect and/or refract from the fluid interface 4 within the annulus.

(21) In performing the above, the distributed acoustic sensing system 1b is able to monitor any changes in the fluid level within the casing 3b around the ESP. This is particularly important to ensure that the ESP 2 remains submerged in fluid, and does not become subject to a gas locking event in which free gas is induced and interferes with the operation of the ESP 2 or any of its components. The liquid surrounding the ESP 2 protects the pump by preventing it from overheating or drying out, and thus preventing damage to the pump that would be costly to repair or replace. The present embodiment is therefore able to detect any unexpected changes in the fluid levels, for example due to superfluous gas, by ensuring that the ESP 2 has enough submergence, thus extending the life of the ESP 2.

(22) Further embodiments of the invention relate to using the distributed acoustic sensor system 1b to determine fluid flow along an ESP activated well. An optical fiber DAS can provide flow profile data with great resolution, sometimes down to 1 m in the case of the Silixa iDAS, but often around 5 m. In more detail, the noise internally generated by the ESP 2 can be coupled into the fluid within the fluid carrying structure, that is, the casing 3b, so as to artificially acoustically illuminate the fluid and allow fluid flow above and below the ESP 2 to be determined. The sensed acoustic wave propagations can then be used to determine the speed of sound in the production fluid and thus the speed of fluid flow in the well. By measuring the speed of fluid flow, the efficiency of the ESP 2 can be monitored. For example, a decrease in the flow rate of the fluid may be an indication that the pump rate has decreased, which may be due to a fault in the ESP 2.

(23) In order to calculate fluid flow velocity, the DAS system 1b is able to measure the phase of the acoustic signal coherently along the fibre optic cable, and transform the time and linear space (along the well) into a diagram showing frequency () and wavenumber (k) in k- space. FIG. 6 shows the time and space signal and FIG. 7 shows the corresponding k- space. Using the data in FIG. 7, a good fit for the speed of sound can be calculated, by determining the gradient of the diagonal lines. The frequency band over which the speed of sound can be determined is more than sufficient for compositional and flow characterization. With the DAS system the speed of sound can be evaluated over a large section of the well and, therefore, measure the distributed variations of the flow composition and characteristics along the well. The technique is particularly powerful for determining the composition of the flow, for example, gas has a speed of sound of around 600 m/s whereas water has a speed of sounds around 1500 m/s.

(24) Using such k- analysis, the speed of sound can also be determined throughout the entire length of the well. Importantly, each of the two diagonal lines shown in the k- space of FIG. 7 corresponds to the speed of sound either travelling up or down the well. These two lines can be analysed to reveal the Doppler-shifted sound speeds for upward and downward propagating sound within the fluid of interest. The measured determined speeds of sound can then be used to determine the flow speed of the production fluid, which is seen to vary with depth in the well corresponding to the change in hydrostatic pressure.

(25) FIG. 8 shows the distributed flow determined in a gas injector based on Doppler shift measurements for a 30 s sampling. The determined flow speed varies with depth in the well corresponding to the change in hydrostatic pressure for a section of tubing with a uniform inner dimension and a gradually sloped well trajectory. In total the instantaneous and locally determined flow is roughly within +/0.3 m/s (that for this well is 10%) of the actual flow speed. The match to reference measurements is within the uncertainties of an instantaneous measurement, the fluid property and the distribution of the pressure drop within the well.

(26) In further detail, it is possible to estimate the speed of a given flow by monitoring the speeds of sound within that flow. In this analysis, it is assumed that the flow direction is coincident with the array layout (e.g. the direction of arrival for acoustic signals is known to be 0 or 180 degrees). The main principle used is that any sound contained within the flow reaches each consecutive sensor with a certain delay. Knowledge of the spatial sampling (i.e. the distribution of the cable along the well) can be used to calculate speed of sound by taking the ratio of average inter-sensor time difference of arrival and the average spatial distance between sensors. This operation can be easily done in the frequency domain. To perform this operation, in one embodiment one constructs a space-time plot of the signal across a neighbourhood of sensors. The 2D Fourier Transform of information this will give a wavenumber-frequency (k-) plot.

(27) If the speed of sound is constant across all frequencies (i.e. there is no dispersion) then each frequency () of a signal will correspond to a certain wavenumber (k) on the k- plot. Thus ideally a space-time signal will be mapped into a single straight line on the k- plot. From the wave equation we know that kc=w, where c is the speed of sound. So estimating the slope of the line of highest energy on the k- plot will give us the speed of sound in the medium.

(28) Since the waveguide can sustain propagation both along and against the direction of flow, the k- plot can show two slopes for each mode of propagation: one positive and one negative. As the slope of each of these lines indicates the sound speed in each direction, the Doppler method can be used to derive the speed of sound from the 2D FFT according to the well-known method of analysis below.
c+=c+v[speed of sound along the flow]
c=cv[speed of sound against the flow]
c+ and c are found as slopes on a k- plot. Combination of the two equations above gives the flow speed (Ev.sup.1) as v=(c+c)/2.

(29) Please note that whilst the above description makes use of processing using k- plots, in other embodiments different processing may be undertaken to achieve the same results, and not all embodiments of the invention are required to use the k- techniques described.

(30) A third embodiment of the invention will be described with respect to FIG. 9. The third embodiment relates to monitoring the annulus fluid level in the vicinity of an ESP using the speed of sound measurements made by the DAS system 1b, as described above. As stated previously, it is important that there is liquid around the ESP during its operation in order to protect an ESP. Within the third embodiment the DAS system 1b is used to monitor liquid levels around the ESP.

(31) FIG. 9 provides a flow diagram illustrating the sequence of operations in the present embodiment, given the equipment described above. In particular, at s.90 the distributed acoustic sensor system 1b is operated in order to monitor the annulus fluid level 4 within the casing 3b, as shown in FIG. 1. To monitor the annulus fluid level 4, in one embodiment the ESP 2 is used as an acoustic source and the distributed acoustic sensor system 1b used to measure the speed of sound above and below the ESP 2, as given in s.91 and s.92, and to identify spatially abrupt changes in the speed of sound as a result of impedance mismatches as acoustic energy from the ESP 2 couples into the wall of the casing 3b and production well 3a. For example, the distributed acoustic sensor system 1b is used to identify a change in speed of sound as a result of weak coupling of the acoustic energy into the wall of the casing 3b and production well 3a above the fluid interface 4. Alternatively, and particularly when the ESP is not operating, other acoustic sources may be used as the acoustic illumination that is detected by the DAS. For example, acoustic energy from external sources can be coupled into the well, and used as acoustic illumination to determine the fluid levels. Such external acoustic energy may be naturally occurring, or result from external events such as seismic surveying. Alternatively, sound sources from within the well itself might be used. For example, where fluid is flowing within the pipe, flow noise from the fluid might be used (if loud enough), or alternatively synthetic noise sources such as clickers driven by fluid flow, or electrically driven sounders may be used to provide a sound source. Whichever sound source is used, it needs to be loud enough in the vicinity of the ESP so that it is detectable by the DAS, so that the DAS can determine the annulus fluid level around the ESP.

(32) In more detail, the distributed acoustic sensor system 1b measures the speed of sound when the ESP 2 is turned off, wherein the speed of sound is measured both above and below the pump. When the ESP 2 is turned off, there may be no speed of sound measurements made since there are no acoustic signals propagating within the casing. However, if any speed of sound measurements are made, this may indicate the presence of acoustic signals which at this point may indicate that there is a problem with either the ESP 2 or the well as a whole, for example, an external disturbance. The ESP 2 may then be turned on, and at s.92 the distributed acoustic sensing system 1b is able to measure the speed of sound as acoustic signals generated by the ESP 2 propagate within the casing 3b, the measurements being made above and below the ESP 2, as before. At s.93, changes in the speed of sound are detected, in particular, spatially abrupt changes in the speed of sound resulting from impedance mismatches above the fluid interface 4. Below the fluid interface 4, the acoustic energy emitted from the ESP 2 is coupled into the casing 3b and the production well 3a, aided by the presence of the fluid within the casing 3b. In contrast, there is significantly weaker coupling of the acoustic energy into the wall of the casing 3b and the production well 3a above the fluid interface 4 where there is an absence of fluid. Consequently, there is a reduction of high speed acoustic energy above the fluid interface 4 and, therefore, the point at which there is a spatially abrupt change in speed of sound indicates the location of the fluid interface 4.

(33) In performing the above, the distributed acoustic sensing system 1b is able to monitor any changes in the fluid level within the casing 3b around the ESP. This is particularly important to ensure that the ESP 2 remains submerged in fluid, and does not become subject to a gas locking event in which free gas is induced and interferes with the operation of the ESP 2 or any of its components. The liquid surrounding the ESP 2 protects the pump by preventing it from overheating or drying out, and thus preventing damage to the pump that would be costly to repair or replace. The present embodiment is therefore able to detect any unexpected changes in the fluid levels, for example due to superfluous gas, by ensuring that the ESP 2 has enough submergence, thus extending the life of the ESP 2.

(34) It should be noted that the same optical fiber DAS system can be used to perform any or all of the above described embodiments, substantially simultaneously. That is, once installed a DAS system is able to monitor the operation of the ESP by detecting and monitoring its operating frequencies, as well as detecting ESP sound coupled into annulus fluid to monitor fluid levels around the ESP, whilst at the same time using the same sound for fluid flow determination. Use of an optical fiber DAS system therefore provides for comprehensive monitoring of the status and operation of a submersible pump installed within a well.

(35) In addition to speed of sound measurements, DAS can be used to determine flow rate by tracking eddies generated by turbulent flow as described previously. In this case densely spaced sensing fibre may be attached below or above the ESP as well as at different locations along the production tubing and/or casing.

(36) The above embodiments describe determining the annulus fluid level in an ESP activated well, using a DAS to identify the fluid interface either by identifying acoustic reflections from the interface, or by identifying the step change in the speed of sound between the two acoustic conductive media either side of the interface. Within the above the acoustic energy source for the DAS can either be the ESP itself, or some other acoustic illumination source, such as flow driven clickers or sounders, electrically driven clickers or sounders, or some other acoustic illumination source, such as an external source such as a seismic pulse from nearby seismic surveying. In some embodiments the acoustic illumination may be fluid flow in the well itself, particularly where that flow is noisy. For example, noisy flow, for example from turbulent or non-laminar fluid flow, within the well may also provide sufficient acoustic energy to act as an acoustic illumination source. In view of the fact that is possible in some embodiments to use an acoustic illumination source that is not the ESP, in further embodiments of the invention the same techniques as described above may be used with such non-ESP acoustic illumination source(s) to provide for in-well fluid level detection, and particularly annulus fluid level detection in any well, whether it is ESP activated or not. That is, in such further embodiments in-well fluid level detection, and particularly annulus fluid level detection may be undertaken in wells that are not provided with an ESP.

(37) In more detail, one quality measure that is often used for oil wells is the Productivity Index (PI). The PI of a well is an indicator of the ability of the reservoir to produce fluid flow in relation to the reservoir pressure and can be represented by,
PI=Production Rate/(RPBHFP)
where RP is Reservoir Pressure, and BHFP is Bottomhole Flowing Pressure. The Production Rate is measured in barrels of oil (bbl) per day i.e. bbl/d

(38) Knowing various parameters including the annulus fluid level and flow rate means that the productivity index can be determined. Typically a lower fluid level will indicate a lower bottomhole flowing pressure. Thus measuring the annulus fluid level per se in any well, whether ESP activated or not, can provide important information about the well.

(39) In respect of measuring the in-well fluid level, and particularly the annulus fluid level in an ESP activated well for the purpose of determining PI, the above described embodiments may be used as described to determine the fluid level. In particular, conveniently the ESP may be used as the acoustic source, again as described previously.

(40) Where no ESP is present, then again the above described embodiments may be used as described, but another source of acoustic energy should be used to provide acoustic illumination for the DAS. However, as described previously, various forms of acoustic illumination can be provided, such as mechanical or electrical clickers or sounders, flow-driven devices, noisy flow, or incident external acoustic energy, for example from seismic shots, that is coupled into the well from the surrounding ground.

(41) With this further embodiment, therefore, it should be understood that the arrangements provided by embodiments of the invention can be used for in-well fluid level detection more generally, and in particular annulus fluid level detection, whether the well is ESP activated or not. The fluid levels thus detected can then be used in various calculations to determine one or more quality measures for the well, such as the Productivity Index mentioned above.

(42) Various modifications to the above described embodiments, whether by way of addition, deletion or substitution, will be apparent to the skilled person to provide additional embodiments, any and all of which are intended to be encompassed by the appended claims.