Downhole Gas Influx Detection

Abstract

A technique enables determination of gas influx in a fluid handling system. A tubing is provided for conducting fluid flow therethrough. Pressure signals are transmitted through the fluid in the tubing. Parameters of the pressure signal, e.g. time and/or attenuation, are measured at a first location and a second location along the tubing. Parameter data is evaluated to determine the occurrence of changes indicative of gas influx into the tubing.

Description

BACKGROUND

In many types of well related operations, gas influx can be problematic. For example, in coiled tubing operations, such as cleanouts, gas influx into the coiled tubing string is undesirable.

Attempts have been made to detect this influx of fluid, particularly the influx of gas. For example, gas influx or “kick” has been detected by determining the round-trip transit time of mud pump noise. An alarm signal is generated when the rate of change in transit time exceeds a predetermined threshold. In another example, the Doppler frequency shift of a mud pump signal is expressed as a ratio signal and compared with a threshold signal to determine gas influx. However, these relatively complex attempts to determine the presence of gas influx are problematic for a variety of applications.

SUMMARY

In general, the present invention provides a method and system for determining gas influx in a fluid transport system, such as a well system. In a well system application, a tubing is deployed in a wellbore, and a pressure signal is transmitted downhole through a fluid in the tubing. Parameters of the pressure signal, e.g. time and attenuation, are measured at an uphole location and a downhole location. Parameter data is evaluated to determine the occurrence of changes indicative of gas influx into the tubing.

BRIEF DESCRIPTION OF THE DRAWINGS

Certain embodiments of the invention will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements, and:

FIG. 1 is a front elevation view of a fluid transfer system, according to an embodiment of the present invention;

FIG. 2 is a front elevation view of a well system deployed in a wellbore and having a gas influx detection system, according to an embodiment of the present invention;

FIG. 3 is a schematic view of a control system that can be utilized in the well system to evaluate specific, measured parameters, according to an embodiment of the present invention;

FIG. 4 is a graphical representation of a typical change in the sound velocity of a pressure signal resulting from an increasing gas fraction in the fluid through which the pressure signal travels, according to an alternate embodiment of the present invention;

FIG. 5 is a graphical representation of a series of pressure signals measured at an uphole location and a downhole location, according to an alternate embodiment of the present invention;

FIG. 6 is a graph illustrating delay time for each sequential pressure pulse signal, according to an alternate embodiment of the present invention; and

FIG. 7 is a graph illustrating the signal attenuation for each sequential pressure pulse signal, according to an alternate embodiment of the present invention.

DETAILED DESCRIPTION

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

The present invention relates to a methodology and a system for determining the influx of gas in a variety of fluid handling systems. For example, the methodology and system can be used to determine whether gas influx has occurred within tubing used in a well application. In the well environment, coiled tubing is used in a variety of well related procedures, including production procedures, cleanout procedures, stimulation procedures and other procedures. Often the influx of gas can be detrimental to the operation, and the present system and methodology enable such gas influx to be detected and evaluated. As described in greater detail below, variations in the speed of sound within the tubing are indicative of a gas influx. The variations are monitored via specific parameters, e.g. travel time, of a pressure signal transmitted through fluid within the tubing. Other parameters, such as attenuation of the signal, also can be monitored and utilized in determining gas influx into coiled tubing or other tubing.

Referring generally to FIG. 1, an example of a fluid transfer system 20 is illustrated according to an embodiment of the present invention. In this example, fluid transfer system 20 comprises a tubing 22 through which a liquid is flowed, as indicated by arrow 24. When a signal is introduced into the liquid within tubing 22, parameters related to that signal can be measured at distinct locations, such as a first location 26 and a second location 28. For example, the signal may comprise a pressure signal that travels along tubing 22 at the speed of sound. However, the speed of sound changes upon the introduction of gas, i.e. gas influx, into tubing 22. Thus, by monitoring changes in specific parameters, e.g. travel time, the occurrence of gas influx can be determined. Another example of a specific parameter that provides an indication of gas influx is signal attenuation. Generally, the pressure pulse signal undergoes greater attenuation following the influx of gas into tubing 22.

The fluid transfer system 20 can be utilized in well applications in which tubing 22 is deployed in a wellbore 30. By way of specific example, the fluid transfer system 20 can be utilized in a cleanout procedure or other liquid delivery procedure in which a liquid is delivered downhole through an appropriate opening or openings 32. In well related applications, first location 26 may be an uphole location, and second location 28 may comprise a downhole location. Additionally, sensors may be utilized at other locations to detect desired parameters useful in monitoring the well. For example, a pressure sensor can be deployed at an external annulus location 34 to monitor annulus pressure. Similarly, an additional pressure sensor can be deployed at a wellhead location 36 to monitor wellhead pressure. A variety of other instruments can be used at these and other locations to detect parameters related to a specific well application.

Referring generally to FIG. 2, system 20 comprises a well system deployed in a well and specifically in a wellbore 30. A gas influx detection system 38 comprises a pressure modulation device 40 designed to transmit a pressure signal downhole through tubing 22, e.g. through coiled tubing. The sound velocity in tubing 22 is monitored via the travel time of the pressure signal from an uphole location 26, such as a surface location, to a downhole location 28, such as a bottom location. Additionally, the attenuation of the same pressure signal can be monitored to determine the occurrence of gas influx. By way of example, pressure modulation device 40 may comprise a valve 42 positioned at an outlet of the coiled tubing 22. The pressure signal is then created, for example, by opening and closing valve 42. Parameters of the pressure signal are measured by a first sensor 44 at uphole location 26 and a second sensor 46 at downhole location 28.

Sensors 44 and 46 measure desired parameters of the pressure signal, such as time and pressure level. By measuring the time at which the pressure signal passes first sensor 44 and second sensor 46, the travel time or time delay between sensors 44 and 46 can be determined for the signal. Additionally, by measuring the intensity of the pressure signal at first sensor 44 and second sensor 46, attenuation of the signal can be determined. Changes in the travel time and/or attenuation are indicative of changes in the fluid through which the pressure signal travels within tubing 22. Determination of the time delay, attenuation or other desired parameters can be performed on a control system 48 based on data output by sensors 44, 46 and pressure modulation device 40.

A variety of control systems 48 can be used with gas influx detection system 38. However, one example is illustrated schematically in FIG. 3. In this embodiment, control system 48 comprises an automated system that may be a computer-based system having a central processing unit 50, such as a microprocessor. Processing unit 50 is operatively coupled to a memory 52 as well as an input device 54 and an output device 56. Input device 54 may comprise a variety of devices, such as a keyboard, mouse, voice-recognition unit, touchscreen, other input devices, or combinations of these devices. Output device 56 may comprise a visual and/or audio output device, such as a monitor having a graphical user interface. The control system 48 can be programmed to provide an operator with a variety of data related to measured parameters and calculations based on those parameters. The processing of data, as well as the control of pressure modulation device 40 and/or sensors 44, 46, may be performed on a single device or multiple devices at the well location, away from the well location, or with some devices located at the well and other devices located remotely.

Liquid and gas have very distinct acoustic properties. Incursion of even a small amount of gas in a liquid results in significant changes in its acoustic behavior. For example, the propagation speed of sound dramatically decreases. This sensitivity to the influx of gas causes significant change in the travel time of the pressure signal from first sensor 44 to second sensor 46. The speed of sound in liquid, gas, and liquid-gas mixtures can be characterized mathematically with the following defined terms and equations:

x: gas volumetric fraction;
c_l, c_g speed of sound in liquid and gas;
ρ_l, ρ_g liquid and the gas density; and
K_l, K_g liquid and gas compressibility.

Mixture compressibility: K=x·K_g+(1−x)·K_l

Mixture density: ρ=x·ρ_g+(1−x)·ρ_l

Speed of sound in medium i: c_i²=1/(ρ_i·K_i)

Speed of sound in mixture: c²=1([x·ρ_g+(1−x)·ρ_l]·[x·K_g+(1−x)·K_l])

The speed of sound, and thus the speed of the pressure signal, varies with both pressure and temperature. However, the pressure dependency for gas is marginal at low pressure. The travel speed of the pressure signal decreases dramatically as the gas fraction within the fluid increases, as illustrated graphically in FIG. 4. In FIG. 4, a graph 58 is used to plot the speed of travel in a fluid versus the gas fraction within that fluid. Graph 58 is typical of liquid and gas mixtures and is representative of, for example, the influx of methane into water. However, similar graphs apply to a wide variety of liquid and gas mixtures.

In graph 58, the speed of travel is illustrated by a solid line 60, while its derivative is illustrated by the x-line 62. As demonstrated, the speed at which a signal propagates through the fluid has a high sensitivity to the presence of even small amounts of gas in liquid. At higher gas fractions, however, the sensitivity decreases substantially. In the example illustrated in FIG. 4, the speed reduction is approximately 40% for 1% gas influx and 60% for 3% gas influx. The speed reduction as a function of gas fraction can be used in programming control system 48 to calculate the gas fraction resulting from gas influx.

The properties of liquid-gas mixtures enable the use of gas influx detection system 38. In FIG. 5, one example of a pressure signal is illustrated in the form of a pressure pulse signal in which a series of pressure pulses 64 are generated by pressure modulation device 40 at specific time intervals, as represented by time interval 66. The pressure and time of each pressure pulse 64 is measured at first sensor 44, as represented by graph line P₁. Similarly, the pressure and the time of each pressure pulse 64 is measured at second sensor 46, as represented by graph line P₂. Due to the travel time of the pressure signal, there is a time delay between detection of the pressure pulse at first sensor 44 and second sensor 46, as represented by time delays D1, D2 and D3 in FIG. 5. The time delays remain generally consistent if there are no changes to the fluid within tubing 22, as illustrated by the consistent time delays D1 and D2. However, assuming tubing 22 is filled with a liquid, the time delay increases upon the influx of a gas, as represented by the increased time delay D3. As indicated by the graph line P₂ the pressure pulse 64 also undergoes attenuation indicative of the gas influx. The longer delay and increased attenuation are useful as the signature of a gas intrusion into tubing 22.

Control system 48 can be used to process the data provided by sensors 44, 46 and to display the data to an operator in graphical form or other forms. For example, the control system can be used to display a delay time diagnostic plot, as illustrated in FIG. 6. The illustrated delay time diagnostic plot is based on the pulse signal input into tubing 22 that is illustrated graphically in FIG. 5. The plot indicates the relatively constant delay for the first two pulses 64 followed by the dramatic increase in delay time as the third pulse 64 travels from first sensor 44 to second sensor 46. As described above, the dramatic increase is indicative of gas influx into tubing 22.

The data can be processed and displayed in a variety of other forms, including the amplitude ratio versus pressure signal illustrated in the signal attenuation diagnostic plot of FIG. 7. The illustrated signal attenuation diagnostic plot is again based on the pulse signal input into tubing 22 that is illustrated graphically in FIG. 5. The plot indicates the relatively constant amplitude ratio of the pressure signal for the first two pulses 64 followed by a dramatic decrease in amplitude ratio as the third pulse 64 travels from first sensor 44 to second sensor 46. The decrease in amplitude ratio reflects an attenuation of the signal that is also indicative of gas influx into tubing 22.

Control system 48 can be programmed to monitor the selected parameters, e.g. time delay and attenuation, to determine changes that indicate gas moving into tubing 22. The control system 48 is then able to output this information to an operator via output device 56. Depending on the source of the pressure signal, control system 48 can be programmed to compensate received/emitted signals due to possible variations in the intensity of the source signal. However, if pressure modulation device 40 can provide sufficient reproducibility of a consistent pressure signal, determination of gas influx can be achieved by comparing each pressure signal received at second sensor 46 with a baseline value. The baseline value can be obtained, for example, through a calibration phase in 100% liquid at the predetermined depth of second sensor 46.

Depending on the application and/or environment in which gas influx detection system 38 is utilized, a variety of pressure modulation devices 40 can be employed. In well applications, for example, a throttle valve or similar equipment may be used to create the pressure signal, either as simple pulses or a continuous wave. If the signal is created as pressure pulses, the time between pulses and the pulse intensity are selected based on a variety of factors, such as travel time to second sensor 46, predicted attenuation, potential reflections of the signal, and other factors. For example, the propagating pressure signal is increasingly attenuated over distance, and the characteristic decay length is a function of pipe diameter, signal frequency, compressibility and viscosity. These factors are taken into consideration when selecting sensors 44, 46 and designing detection system 38 for a given tubing and application.

In some environments, the broadband character of pulses may create difficulty in extracting the signal from environmental noise. For these applications, detection of a continuous wave pressure signal can be more reliable. Generally, environmental noise inside the coiled tubing utilized in well related applications is fairly low, rendering these applications suitable for pressure signals in the form of either pulses or a continuous wave.

Gas influx detection system 38 and its control system 48 also can be designed to detect and monitor a variety of other parameters to ensure accurate detection of gas influx. For example, flow sensors can be utilized to measure fluid velocity, and additional pressure sensors can be used to provide data on the pressure gradient present in the coiled tubing. The pressure gradient and flow velocity can affect detection of the gas fraction, for example, because movement along the pressure gradient causes a change in the volumetric gas fraction within the coiled tubing. However, the properties of the liquids and gases, e.g. density, sound velocity, compressibility, etc., enable the control system 48 to be readily programmed, as necessary, to compensate for these external factors.

The overall gas influx detection system 38 is useful in many types of fluid transfer systems 20 employed in well related applications and other applications. Additionally, the system can incorporate a variety of components; including a variety of first sensors 44 and second sensors 46 as well as a variety of acoustic modulation devices 40 to input suitable pressure signals. Furthermore, additional parameter sensors can be deployed along the tubing 22 or within a plurality of zones along tubing 22 to monitor gas influx at a plurality of locations. Control system 48 also can be programmed to process many types of data provided by sensors 44, 46 and to output related data, predictions, results, and other information related to the influx of gas, gas fraction, or effects of the gas influx.

It is important to note that the above described systems and methods of determining gas influx may be practiced in both a reverse cleanout procedure (wherein a cleanout fluid is pumped down the annulus of a well and returned up the coiled tubing), and a conventional cleanout procedure (wherein a cleanout fluid is pumped down the coiled tubing and returned up the annulus of the well).

Accordingly, although only a few embodiments of the present invention have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this invention. Accordingly, such modifications are intended to be included within the scope of this invention as defined in the claims.

Claims

1. A method of determining gas influx, comprising:

deploying a tubing in a wellbore;

transmitting a pressure signal downhole through a fluid in the tubing;

measuring a time delay and an attenuation of the pressure signal at a downhole location; and

outputting data, corresponding to the time delay and the attenuation, to a control system for determining the occurrence of gas influx into the tubing.

2. The method as recited in claim 1, wherein deploying comprises deploying a coiled tubing in the wellbore.

3. The method as recited in claim 1, wherein transmitting comprises utilizing a valve to create the pressure signal.

4. The method as recited in claim 1, wherein transmitting comprises transmitting a pulse signal.

5. The method as recited in claim 1, wherein transmitting comprises transmitting a continuous wave signal.

6. The method as recited in claim 1, further comprising utilizing the control system to calculate a gas fraction resulting from gas influx.

7. The method as recited in claim 1, further comprising utilizing the control system to compare the time delay and attenuation of a plurality of sequential pressure signals to determine changes indicative of gas influx.

8. The method as recited in claim 1, further comprising utilizing the control system to compare the time delay and attenuation to a baseline time delay and attenuation to determine the occurrence of gas influx.

9. A system, comprising:

a tubing deployed in a wellbore;

a pressure modulation device to transmit a pressure signal downhole through the tubing;

an uphole sensor to detect time and pressure of the pressure signal;

a downhole sensor to detect time and pressure of the pressure signal; and

a control system coupled to the uphole sensor and the downhole sensor to measure a time delay of the pressure signal as it moves from the uphole sensor to the downhole sensor, the control system being able to use the time delay to determine a gas influx in the tubing.

10. The system as recited in claim 9, wherein the tubing comprises coiled tubing.

11. The system as recited in claim 9, wherein the pressure modulation device comprises a valve.

12. The system as recited in claim 9, wherein the pressure modulation device is used to transmit a pulse signal.

13. The system as recited in claim 9, wherein the pressure modulation device is used to transmit a continuous wave signal.

14. The system as recited in claim 9, wherein the control system is operated to determine an attenuation of the pressure signal.

15. A method, comprising:

transmitting a pressure signal along a fluid disposed in a tubing; and

determining whether an influx of gas into a liquid has occurred within the tubing by measuring at least one of a speed change and an attenuation of the pressure signal.

16. The method as recited in claim 15, further comprising deploying the tubing in a wellbore.

17. The method as recited in claim 16, further comprising using the tubing for a cleanout procedure.

18. The method as recited in claim 16, wherein determining comprises measuring the pressure and time of the pressure signal at an uphole position and at a downhole position.

19. The method as recited in claim 18, further comprising outputting data obtained at the uphole position and the downhole position to a processor-based control system.

20. A method, comprising:

deploying a coiled tubing string downhole for a well operation;

transmitting a pressure signal along an interior of the coiled tubing;

measuring the length of time required for the pressure signal to travel between two locations along the coiled tubing; and

determining whether a gas has mixed with liquid in the coiled tubing based in the pressure signal travel time between the two locations.

21. The method as recited in claim 20, wherein transmitting comprises transmitting a pulse signal.

22. The method as recited in claim 20, wherein transmitting comprises transmitting a continuous wave signal.

23. The method as recited in claim 20, wherein transmitting comprises transmitting the pressure signal from an uphole location to a downhole location.

24. The method as recited in claim 20, wherein measuring further comprises measuring an attenuation of the pressure signal.

25. The method as recited in claim 24, wherein determining comprises processing time and attenuation data on a processor-based control system.