Patent Grant
7357021
The present invention relates to methods of monitoring downhole conditions in oil and/or gas wells and arrangements of apparatus therefor and more particularly but not exclusively relates to the use of fiber optic or electronic monitoring methods for oil and/or gas wells.
Conventionally, it is known to conduct “noise log” operations in oil/gas wells. The noise log tool is an instrument sensitive to acoustic signals and is run into a well on the end of an electrical cable attached to, or contained within a wireline, in order to move it past zones of interest.
Accordingly, as the noise log tool is drawn past the zones of interest, anomalies or differences from a baseline log (i.e. a log already conducted) can be used to infer information on the flow of the production fluids (i.e. the oil and/or gas) passing up the well from the production zones. Such conventional noise log technology, however, provides only a “one-shot” survey, in that it only provides information when the noise log tool is actually run into the well and therefore cannot provide a permanent monitoring system since the noise log tool cannot reside permanently within the well. Furthermore, the measurements provided by the noise log tool may be affected by the very presence of the noise tool in the flow.
It is also known to use optical fibers deployed in oil and/or gas wells, where the optical fibers are provided with a number of Fiber Bragg Gratings (FBGs). By way of background, FBGs have been in use for many years in the telecommunication industry and have been used more recently in the downhole oil and gas industry. Hitherto, the FBGs have been used to act as sensors to monitor seismic activity in the oil and/or gas reservoir; in other words, they listen for movement such as cracking in the rock of the reservoir. An article entitled “Downhole Monitoring: Listening with Light” published in April 2003 on pages 26 to 30 in Offshore Engineer publication discusses such known use of FBGs.
According to a first aspect of the present invention there is provided a method of determining and/or identifying the flow of fluid in a well comprising monitoring the signal received from two or more sensors located in a well and analysing the frequency of said signals over time to determine a flow regime for production of fluids.
Preferably, the method further comprises continued monitoring of the signal received from the one or more sensors to create an acoustic profile of the well.
Typically, the sensors are provided on an elongate member and preferably, the sensors comprise optically based sensors and the elongate member comprises an optical fiber. Most preferably, the sensors comprise Fiber Bragg Gratings (FBGs).
Typically, the signal that is monitored is an interferometric signal of a section of the elongate member located between two sensors. Preferably, a plurality of interferometric signals are monitored for a respective plurality of sections of the elongate member.
The method preferably further comprises creating a flow regime based upon the signals monitored and preferably further comprises comparing the flow regime to a reference flow regime.
According to a second aspect of the present invention there is provided a method of determining sand production in a well comprising monitoring the signal received from one or more sensors located in a well and analysing the frequency of said signals for indications of sand production.
Typically, the sensors are one or more optical based sensors which are typically provided on an optical fiber.
Preferably the one or more sensors are Fiber Bragg Gratings and preferably there are a plurality of FBGs provided on the optical fiber, and more preferably, said FBGs are arranged to be vertically spaced apart when deployed in the well.
Preferably, the frequency of said signals is analyzed by comparing the signals from two vertically spaced apart sensors.
According to a third aspect of the present invention there is provided a method of identifying localized events in a well comprising monitoring the signal received from one or more sensors located in a well and analyzing the frequency of said signals for localized events.
Typically, such localized events can include any one, more than one or all of the following:
Typically, the method according to the third aspect is used in conjunction with, or following, the method according to the first aspect of the present invention, where the localised events are identified by comparing the signal received from one sensor with the signals received from one or more of the other sensors located in the well.
The method of the third aspect may be conducted whilst the well is shut in; in other words, the method of the third aspect may be conducted whilst the well has been prevented from producing production fluids.
According to a fourth aspect, the present invention provides a method of determining the apparent flow velocity of fluid flowing through a conduit, comprising the steps of:
Typically, the conduit is a downhole tubing and is preferably a production tubing for carrying oil and/or gas from a production zone of hydrocarbon reservoir to the surface of the well. Typically, the distance between the first and second sensors is known.
The event may be a thermal event such as a change in temperature in the production fluid and may be a naturally occurring thermal event such as a change in the temperature of the production fluid leaving the production zone of the reservoir.
Alternatively, the thermal event may be an induced thermal event caused by fluid being injected into the production tubing at a different temperature to the temperature of the production fluid.
Alternatively, the event may be an acoustic event and further may be an induced acoustic event such as a sound created by a collision of a moveable member such as a piston.
Alternatively, the event may be a pressure event such as an increased pressure of the production fluid which may be generated by injection of fluid into the production tubing; in this situation, the first and second sensors are preferably first and second pressure sensors.
According to a fifth aspect, the present invention provides a method of monitoring the strain in downhole tubulars comprising the steps of:
Preferably, the method firstly comprises the steps of providing the tubular with at least one receiver and may further comprise providing the tubular with a transmitter. Typically, the transmitter and receiver are respectively an acoustic transmitter and receiver.
Typically, the downhole tubular comprises a casing or liner string and the receiver is typically located on the outer surface of the casing or liner string on a cable protection means at a casing joint coupling means.
Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which:
An optical fiber 10 provided with a plurality of FBGs 12 is installed downhole in an oil/gas/water well of interest as shown in
The FBGs 12 are placed in appropriate and desired locations within the well depending upon the particular deployment mechanism chosen, and it should be noted that the optical fiber 10 carrying the FBGs 12 can be deployed with, or instead of, conventional electronic or fiber downhole monitoring systems in a similar fashion thereto; that is the optical fiber 10 carrying the FBGs 12 can be fixed inside or deployed into a protective tube 14 attached to one of the downhole tubular strings such as the production tubing string 16 which acts as a conduit for the flow of the produced hydrocarbons from the production zone reservoir to the surface. As shown in
As is known, the deployed FBGs 12 respond to strain or other displacement of the optical fiber 10, such as temperature, and the response can be measured by monitoring data analysis equipment 22 which is coupled to the upper end of the optical fiber 10 (see
It should be noted that interferometric techniques, which have hitherto been used to monitor seismic movement, can be also used to make measurements of the acoustic signal sensed in the fiber section between two FBGs 12.
The reader should note that while the embodiments of the methods described below will be useful in their own right, many of the embodiments can be additionally useful through use of a conventional temperature profile in conjunction to the measured acoustic profile. In other words, the FBGs 12 can be used in their conventional manner to act as multiple single point temperature measurement sensors, in conjunction with the acoustic embodiments described subsequently. This may be additionally useful because temperature profiles are conventionally used to obtain information on the performance of a well and additional acoustic information or analysis (or simply confirmation of existing interpretation) can be achieved if the additional acoustic information in accordance with the present invention is utilised.
One or more embodiments in accordance with the first aspect of the present invention will now be described.
When a fiber 10 containing FBGs 12 as described above is deployed downhole, an interferometer can be used to measure the acoustic signal between each successive FBG 12. If, for example, a sensor system comprising 20 FBGs 12 are present on a deployed fiber 10, separate acoustic measurements can be made of the 19 sections between these FBGs 12. For any given period of time, an “acoustic profile” can therefore be created for the section of the well across which the FBGs 12 are deployed.
This is of interest because aspects of the acoustic signal such as the frequency components and their amplitude, will be a function of parameters such as the fluid type and flow regime of the flow past the sensor system. For given types of fluids, flow regimes and flow patterns can be characterised in terms of the properties of the acoustic signal generated, and thus the flow regime past the sensor system can be identified by comparison to a series of reference flow regimes or flow patterns.
One or more embodiments in accordance with the second aspect of the present invention will now be described.
Sand flowing with the production fluid will generate noise as it impinges upon any restriction or otherwise comes in contact with any solid object, such as the wall of the production tubing 16. In relation to the production of clean fluids, sand-contaminated fluids generate discernible high-frequency components of the flow noise.
When an FBG 12 sensor system is deployed as described above, spectral analysis of the acquired acoustic signal can be used, particularly when referenced to an initial ‘baseline’ data set, to identify sand production or flow past the sensor.
One or more embodiments in accordance with the third aspect of the present invention will now be described.
An acoustic profile can also be used to identify the presence of flow behind casing 20 or in the annulus between the tubing 16 and the casing 20 because such flow will generate an acoustic signal. When a well is provided with an optical fiber 10 carrying FBGs 12 or is otherwise instrumented as described above is shut in (not flowing), or is flowing at a low rate, or when a measurement is compared to a baseline reference survey, acoustic events detected across a particular section, but not across the rest of the instrumented section, are indicative of localised events.
Acoustic activity when the well is shut in is an indication of possible flow behind the tubing, or from tubing 16 to annulus (or vice versa).
Similarly, a leak in the tubing 16 will generate noise. A leak may not be easily detectable on a thermal profile if it is too small to generate significant thermal effects, whereas the acoustic frequency characteristics of such a leak may be quite distinctive. The acoustic profile can thus be used to identify and locate tubing 16 leaks.
Similarly, cross-flow from one zone to another will generate flow noise. When the well is shut in, flow noise between two or more zones is indicative of cross-flow. The acoustic profile can thus be used to identify and locate cross-flow between zones.
Embodiments in accordance with the fourth aspect of the present invention will now be described.
Determining Apparent Flow Velocity from Naturally Occurring Thermal Events
An important application of temperature measurements across the reservoir is the allocation of flow to particular zones. Whilst a correlation exists between the temperature profile and flow from a particular zone, this relationship depends on a number of variables and is notoriously difficult to quantify. A fluid velocity measurement would significantly improve the reliability and accuracy of flow allocation calculations.
A feature of FBGs 12, particularly in comparison to other downhole fiber techniques such as Raman Distributed Temperature Sensing (DTS), is the ability of high sampling rates. Typically, a Raman DTS system will require from 2-30 minutes to make a measurement. An FBG 12 can be read at a rate of up to several kHz.
Any instability in the flow, i.e. turbulent flow, solids production, slugs or surges, etc., will generate a short term event that cannot normally be detected by the long time-constant Raman DTS measurement. A high sample-rate FBG sensor, however, can detect relatively high-frequency events or transients.
While thermal events can be detected, the thermal lag (created by the time required for heat to be transferred through multiple layers of tubing in conjunction with the heat sink effect of all of the in-well tubulars) limits the detection of such events through purely thermal analysis. An acoustic or mechanical event, however, will be detectable over much shorter time-scales. At any given point, an FBG acoustic sensor 12, for example, will be able to produce a measurement of the level of noise across the measured frequency spectrum. The same measurement can be repeated at a second FBG sensor 12 a little further up the well. Further measurements can be made at subsequent sensors 12 further up the well.
Standard and well-known cross-correlation techniques can be used to calculate when an event passing one sensor reaches a subsequent sensor 12. Knowing the distance between the two sensors 12, this measured “time of flight” of the event can be used to calculate the apparent flow velocity.
Cross-correlation of trace T1 against T2 will determine the time required for the event to travel from FBG #1 to FBG #2. Similarly, the time taken for the event to travel from FBG #2 to FBG #3 can be determined.
From here, a simple [speed=distance/time] calculation will provide the apparent flow velocity.
While there are a number of potential sources of error or uncertainty in individual correlations, these can be overcome by performing multiple or continuous correlations, and stacking (or otherwise averaging) them to remove statistical anomalies. Accuracy, speed of calculation and minimisation of anomalous results can also be improved by limiting the correlation step and interval parameters to approximate expected values of apparent flow velocities.
Determining Apparent Flow Velocity from Induced Thermal Events
When a fiber package 10 is deployed such that the check valve releases into the production bore, as is the case when injected into an existing chemical injection line, a thermal event can be induced in the production bore by injecting fluid past the micro-tube, through the injection line and check valve, into the production bore. This can be seen in
Such injected fluid will normally be at a different temperature than the produced fluid. The resultant thermal event can be observed as it flows with the produced fluid up the production bore. Even where the injected fluid has become warmed up through proximity to the production fluid, it will still be colder (or hotter, if heated fluid is used) than the production fluid.
To generate faster thermal transients, fluid can be injected until a steady state is achieved. At this point, the thermal event may be pulsed, i.e. the injection is stopped and re-started, ensuring the greatest possible temperature differential between injected and produced fluids, and thus generating a distinctive and characteristic transient event that can be detected easily.
Liquid or gas can be injected, as appropriate to be compatible with the fluid being produced. The thermal event may be a “Hot Event” such as the injection of steam or a “Cold Event” such as a cold fluid from surface. Alternatively, thermal events can be induced from surface by changing flow rates, for example, by altering the choke position.
It can be seen from
Provided the distance between the two points is known, Apparent Flow Velocity “V” is simply:
Determining Apparent Flow Velocity from Induced Acoustic Events
A limitation of the previous situation described (Determining Apparent Flow Velocity from induced thermal events) is the thermal lag inherent in temperature changes in the production bore of the production tubing 16 reaching the sensor, which is located on the outside of the production tubing 16.
Knowing the distance “L” between the acoustic generator and two or more sensors, the signal transit time “t” in the production fluid can be measured. The apparent fluid velocity is then derived from the difference between the transit time under flowing and static conditions.
An acoustic source, which is described in more detail below, can be used instead of a thermal source to create an acoustic event that can be measured at two or more sensors 12, and this is shown in
An enhanced embodiment of the method, as shown in
For example, when coupled with an electrical conductor (such as a TEFAC™ cable available from Wood Group in Houston, Tex., USA), an acoustic or ultrasonic source such as Piezo Technologies' ETALON™ range of downhole transducers or alternatively, a mechanical source can be used, similar to those used for electric wireline acoustic logs.
For propagation in the direction of flow,
Vs=(Va+Vf)=L1/t1 (1)
For propagation in the direction opposite to flow,
Vs=(Va−Vf)=L2/t2 (2)
Rearranging (2) gives,
Va=L2/t2+Vf (3)
Substituting (3) into (1) to eliminate Va gives,
Vf=½(L1/t1−L2/t2)
where: L1 and L2 are constants, t1 and t2 are measured variables.
The limitations of this application are likely to be related to the distance a signal can travel and still be detectable, particularly in areas of good cement bond quality, where acoustic signals are attenuated significantly.
Apparent Flow Velocity from Induced Pressure Events
The previous situation described (Determining Apparent Flow Velocity from induced acoustic events) the use of an acoustic signal to determine apparent flow velocity.
Where two pressure sensors are used in place of the acoustic sensors, the same principles can be used to determine the transit time of an induced pressure event, and this is shown in
A means, such as the pressure transient source shown in
Alternatively, a sharper transient may be achieved by interrupting the flow of such an injected liquid or gas. Alternatively, a mechanical chamber (not shown) or electrical solenoid (not shown) can be suddenly released to create a local pressure transient.
In this example, issues of pipe arrival need not be considered, as the only signal path between the pressure transient source and the pressure sensor is through the production fluid.
One or more embodiments in accordance with the fifth aspect of the present invention will now be described.
A receiver or optionally two or more receivers, which may be acoustic, displacement or may use some other principle, are mounted on the casing string (A.) in an oil, gas or water well and this is shown in
The distance travelled by the signal generated (which in the case of
The speed of the signal between generation at the transmitter (B.) and arrival at the receiver (C.) is a well known quantity.
The distance travelled by the signal can then be calculated by measuring accurately the transit time from transmitter to receiver.
When the casing string (A.) is under tension, the distance travelled by the signal from transmitter (B.) to receiver (C.; D.) will increase, which will result in an increase in measured transit time. Similarly, under compression, the measured transit time will decrease.
The limitations of this application are likely to be related to the distance a signal can travel and still be detectable, particularly in areas of good cement bond quality, where acoustic signals are attenuated significantly.
If the casing (A.) is buckled, however, the signal path may be longer than the physical length of the casing (A.), particularly in the case of helical or (to a lesser extent) Euler buckling, leading to under-estimation of the severity of any measured deformation.
A further limitation of this method is introduced by any deformation of downhole tubulars (A.). If the casing (A.) that forms the acoustic signal path is buckled, the signal path may be longer than the physical length of the casing (A.), particularly in the case of helical or (to a lesser extent) Euler buckling, leading to under-estimation of the severity of any measured deformation. In this case, an absolute measurement may be misleading, and it becomes important that a measurement is seen in the context of preceding measurements as any such deformation develops.
Effects of stress on propagation speed such as stress in the metal forming the acoustic signal path will affect the propagation speed of an acoustic (or other) signal. Such effects must be modelled and taken into account in calculating any displacement from propagation speed measurements.
Advantages of this example include:
One or more embodiments in accordance with the sixth aspect of the present invention will now be described.
Stress waves in metals are generated by events such as impact, fatigue cracking, or abrasion. The duration of stress wave emissions is only several microseconds to a few milliseconds. Such transient events propagate away from the initiation site as shear and compression waves at the speed of sound in metal. The shear waves introduce deflections on the surface of the metal which will excite an absolute motion sensor such as an accelerometer or an acoustic sensor.
When a receiver is used which is capable of detecting acoustic or vibrational signals, events in the frequency range of such stress wave emissions can be detected and differentiated from background noise. It should be noted that a series of suitable receivers/sensors, which are preferably a series of FBGs 12 as shown in
Many of the advantages described in the previous embodiments will also hold for this embodiment 6.
The acoustic profile hereinbefore described using the sensors (which are preferably FBGs 12) fixed in position with respect to the production tubing 16 can be virtually simultaneous across the length of the measured section, thus eliminating misinterpretations due to acoustic signal changing with time, which is a disadvantage experienced by conventional “noise log” operations since such a conventional operation may misinterpret, for example, an event that is detectable over a significant length of the zone of interest, but which is not present and consistent as the sensor moves across the zone of interest.
Modifications and improvements may be made to the embodiments hereinbefore described without departing from the scope of the invention. For instance, while the use of optical fiber 10 as hereinbefore described provides advantages in terms of high levels of bandwidth and data communication rate, many of the embodiments hereinbefore described can function equally well using electronic or hybrid systems rather than optical fiber 10 alone. In other words, an electronic or hybrid system could be used instead of or in conjunction with the optical fiber 10 and FBGs 12 to achieve the various monitoring applications described.
Furthermore, other signal types are also considered as alternatives for many of the embodiments hereinbefore described. Electromagnetic pulses are possible, for example, in place of some acoustic signals.
Furthermore, pressure pulses over a known distance through the annulus between the production tubing and casing string may be used to determine the absolute distance from a pressure transmitter to a pressure sensor/receiver by measuring the transit time (by using the same principle as acoustic transmission); in other words, a pressure transmitter and receiver would replace the acoustic transmitter/receiver 12 hereinbefore described, although this will be limited by packers and other pressure retaining devices.
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