US20110122727A1

US20110122727A1 - Detecting acoustic signals from a well system

Info

Publication number: US20110122727A1
Application number: US12/667,978
Authority: US
Inventors: Daniel D. Gleitman; Roger L. Schultz; Robert L. Pipkin
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2007-07-06
Filing date: 2008-07-03
Publication date: 2011-05-26

Abstract

A heated fluid injection string (106) injects heated treatment fluid into a well (102) in a subterranean zone (112) and generates an acoustic signal. An acoustic detector (212) detects the acoustic signal, and an acoustic signal analyzer (214) interprets the detected acoustic signal. In some implementations, the acoustic signal analyzer (214) interprets the detected acoustic signal to determine information about at least one of the heated fluid injection string (106), the well (102), or the subterranean zone (112).

Description

REFERENCE TO RELATED APPLICATIONS

The present application claims the benefit of priority to U.S. provisional patent application Ser. No. 60/948,346 filed Jul. 6, 2007 and U.S. patent application Ser. No. 12/120,633 filed May 14, 2008, both of which are incorporated herein by reference.

BACKGROUND

The present disclosure relates to detecting acoustic signals from a well system.
Treatment fluids can be injected into a subterranean formation to facilitate production of fluid resources from the formation. For example, heated treatment fluids (i.e., heat transfer fluids), such as steam, may be used to reduce the viscosity of fluid resources in the formation, so that the resources can more freely flow into the well bore and to the surface. In another example, treatment fluids may be injected into one or more injection well bores to drive fluid resources in the formation towards other well bores. The components of the well system, including those used for heating the treatment fluid and injecting the treatment fluid, generate acoustic signals.

SUMMARY

In certain aspects, a heated fluid injection string injects heated treatment fluid into a well in a subterranean zone and generates an acoustic signal. An acoustic detector detects the acoustic signal, and an acoustic signal analyzer interprets the detected acoustic signal.
In certain aspects, an acoustic signal generated in connection with injecting heated treatment fluid into a well in a subterranean zone is detected, and the detected acoustic signal is interpreted.
In certain aspects, a fluid injection string generates an acoustic signal in connection with injection of heated treatment fluid into a well in a subterranean zone. An acoustic detector detects the acoustic signal, and an acoustic signal analyzer interprets the detected acoustic signal.
Implementations can include one or more of the following features. The acoustic signal analyzer interprets the detected acoustic signal to determine information about at least one of the heated fluid injection string, the well, or the subterranean zone. The determined information includes information related to at least one of description of the subterranean formation, integrity of the well, or operation of the fluid injection string. The information related to description of the subterranean formation includes information related to at least one of a location of a fluid interface or a movement of a fluid interface. The information related to integrity of the well includes information related to at least one of a leak in a component of the well, a leak in a tool installed in the well, a flow obstruction in the well, or a flow obstruction in a tool installed in the well. The information related to operation of the fluid injection string includes information related to at least one of an air to fuel ratio, a combustion temperature, a combustion efficiency, or a fluid composition. The system includes a controller configured to modify at least one aspect of operation of the fluid injection string based on the information provided by the acoustic signal analyzer. The fluid injection string includes at least one of a fluid oscillator device, a whistle, or a horn. The acoustic detector includes multiple sensors installed in multiple different locations. The acoustic detector includes at least one of a sensor installed in the well, a sensor installed at a terranean surface, or a sensor installed in a different well. The acoustic detector includes at least one sensor installed directly on at least one component of the fluid injection string. The fluid injection string includes a steam generator installed in the well. The heated treatment fluid is injected into the well during multiple time periods to generate the detected acoustic signals. Interpreting the detected acoustic signal includes identifying a property of the detected acoustic signal, the property including at least one of amplitude, phase, or frequency. Operation of a tool installed in the well is modified based at least in part on the detected acoustic signal. Interpreting the detected acoustic signal includes identifying a rising edge of an acoustic signal generated by a fluid oscillator device. Detecting the acoustic signal includes detecting an acoustic signal generated by at least one of a steam generator, a fluid oscillator, a whistle, or a horn. Detecting the acoustic signal includes detecting a primary acoustic signal and a secondary acoustic signal. Detecting the acoustic signal includes at least one of detecting a reflected acoustic signal or detecting a transmitted acoustic signal. The acoustic signal includes a first acoustic signal, and a second acoustic signal is detected and interpreted. Movement of a fluid interface in the subterranean zone is identified based at least in part on the interpretation of the first acoustic signal and the interpretation of the second acoustic signal. Identifying movement of a fluid interface includes identifying movement of a steam front. Properties of the first acoustic signal are compared to properties of the second acoustic signal. Differences between the first acoustic signal and the second acoustic signal are identified. The first acoustic signal is detected during a first time period and the second acoustic signal is detected during a second time period after the first time period. The first acoustic signal and the second acoustic signal are detected during the same time period. The first acoustic signal includes a first set of frequencies and the second acoustic signal includes a second set of frequencies not included in the first set of frequencies. The first acoustic signal is detected at a first location and the second acoustic signal is detected at a second location. The fluid injection string includes a fluid oscillator device that includes an interior surface defining an interior volume of the fluid oscillator device, an inlet into the interior volume, and an outlet from the interior volume. The interior surface of the fluid oscillator device is static during operation to receive the heated treatment fluid into the interior volume through the inlet and to vary over time a flow rate of the heated treatment fluid from the interior volume through the outlet. The fluid injection string further includes an additional fluid oscillator device and a valve to selectively communicate the heated treatment fluid to at least one of the fluid oscillator device or the additional fluid oscillator device. The fluid oscillator device includes a first steam whistle configured to generate an acoustic signal including a first range of frequencies and the additional fluid oscillator device includes a second steam whistle configured to generate an acoustic signal including a second range of frequencies. The system includes a bypass conduit, and the valve selectively communicates the heated treatment fluid to at least one of the fluid oscillator device, the additional fluid oscillator device, or the bypass conduit.
The details of one or more implementations are set forth in the accompanying drawings and the description below. Other features will be apparent from the description and drawings, and from the claims.

DESCRIPTION OF DRAWINGS

FIGS. 1A-1D are schematic, side cross-sectional views of example well systems.

FIG. 2 is a schematic illustration of acoustic signal communication in a well system.

FIGS. 3A-3C are illustrations of example well system components; FIG. 3A is a side view of an example whistle assembly; FIG. 3B is a side cross-sectional view along line 3B-3B of FIG. 3A; FIG. 3C is a side cross-sectional view of an example steam oscillator sub.

FIGS. 4A and 4B are flow charts illustrating example processes for detecting acoustic signals from a well system.

DETAILED DESCRIPTION

The present disclosure relates to gaining information about the operation of a well system and the subterranean formation by detecting and analyzing (interpreting) acoustic signals generated by components of a well system. For example, a well system includes a well bore defined in a subterranean formation and/or equipment installed in the well bore (e.g., a completion string, one or more tools carried by the completion string, casing, packers, control systems, and/or other components). In some cases, a component of a well system generates acoustic signals, for example, during operation of the component. Acoustic signals generated by a component of the well system can be detected by one or more sensors. In some cases, the acoustic signals can be detected after the acoustic signals interact with one or more interaction media of the well system or of the subterranean formation. Analysis of the detected acoustic signals can provide information about the media and/or the well system component that generated the acoustic signals. In some implementations, the acoustic signals can be propagated, reflected, attenuated, phase shifted, filtered, and/or affected in another way by all or a portion of the interaction media, for example, based on an acoustic impedance of the interaction media. Analysis of the propagation, reflection, attenuation, phase shift, filtering, and/or other effects can provide information about the interaction media. Examples of interaction media include fluid and non-fluid media, such as the well bore and components of the well system, treatment fluids, the subterranean formation surrounding the well bore and resources therein, above-surface media, above-surface system components, and/or others.
Acoustic signals may be embodied as mechanical vibrations propagating in a fluid, non-fluid, or any other type of medium. Acoustic signals can include, for example, sound waves, seismic waves, primary waves, secondary waves, tertiary waves, etc. For example, a primary wave can include a direct acoustic signal propagated directly from a source to a detector, and a secondary wave can include a reflected acoustic signal propagated indirectly from the source to the detector. Acoustic signals can include longitudinal waves (e.g., compression waves) and/or transverse waves (e.g., shear waves). Acoustic signals can include a broad range of frequencies. For example, acoustic signals can include frequencies in the range of 1 to 100 Hertz (Hz), 0.1 to 1.0 kHz, 1 kHz to 100 kHz, and/or different frequency ranges. In some implementations, acoustic signals may include one or more frequencies below, within, and/or above audible frequencies. In some implementations, acoustic signals are propagated at frequencies including 1 (Hz) to 100 kHz. In some implementations, acoustic signals are generated by a fluid oscillator system and/or a steam generator system within the subterranean well bore. For example, the steam generator system may include a combustor that generates acoustic signals during operation. As another example, the fluid oscillator system may oscillate compressible working fluid within the well bore to generate acoustic signals for stimulating production from a subterranean zone. At least a portion of the acoustic signals generated by the fluid oscillator system and/or the steam generator system can be detected by one or more sensors. Before reaching the one or more sensors, in some cases, the acoustic signals may interact with interaction media, such as a component of the well system and/or a region of the subterranean formation surrounding the well bore. The interaction of the acoustic signal with the interaction media may depend on an acoustic impedance or variations of an acoustic impedance in the interaction media. Analysis of the detected acoustic signals can provide information about the steam generator system, the fluid oscillator system, the interaction media, and/or others.
In some cases, an acoustic signal can be detected, for example, by acoustic sensors at the surface, acoustic sensors in and/or around the well bore, acoustic sensors in another well bore, and/or acoustic sensors in a different location. For example, an acoustic sensor can include a transducer to convert acoustic signals to electromagnetic signals, such as a hydrophone, geophone or other type of acoustic sensor. In some cases, an acoustic sensor is installed directly on or proximate a sound-generating component of the well system. Analysis of the detected acoustic signals may include a Fourier analysis of various frequency components of the acoustic signals. For example, analysis of the detected acoustic signals may include Fourier transforming time-domain data to identify phase and/or amplitude data at various temporal frequencies. Analysis of the detected acoustic signals may include identifying a rising edge of the acoustic signal, such as the leading edge of a transient signal. Analysis of the detected acoustic signals may include identifying a response function of interaction media. For example, identifying a response function may include analysis of an acoustic signal over plurality of frequencies and/or intensities. Analysis of the detected acoustic signals may provide information about resources and/or formations in a subterranean zone of interest.
Acoustic data can include a single acoustic signal or multiple acoustic signals collected over multiple time periods and/or at multiple different locations. For example, acoustic data can include one-dimensional (1-D) data and/or multi-dimensional (e.g., 2-D, 3-D, 4-D, etc.). A dimension of an acoustic data set may represent any relevant parameter. For example, a dimension of an acoustic data set may represent a spatial parameter (e.g., position or wave number) or temporal parameter (e.g., time or temporal frequency), or another type of parameter (e.g., phase or amplitude). 1-D data may include a reflected (or transmitted) signal amplitude as a function of travel time (and/or travel distance). 2-D data may include a series of 1-D data sets spatially distributed along a trace, for example, to provide cross-sectional data for a subterranean zone. 2-D data may include a series of 1-D data sets temporally distributed over a time-period of interest. 3-D data may include a series of 1-D data sets spatially distributed over an area, for example, to provide volumetric data for a subterranean zone. 4-D data may include a time-series of 3-D data sets.
In certain instances, analysis of the acoustic signals includes interpreting the acoustic signals. For example interpreting the acoustic signals can provide information related to a location of an interface between media of different acoustic impedances, for example a fluid interface, as between one or more of oil, water, gas, steam, and/or another material. A fluid interface can include a steam front, and analysis of an acoustic signal can provide information related to a location, distribution, and/or migration of the steam front. In certain instances, the analysis of the detected acoustic signals may include correlation to seismic data, acoustic logging, and/or other logging data. In certain instances, the analysis may use as inputs the acoustic signals detected during two or more different time intervals, and/or detected waves resulting from a first fluid oscillator device frequency range and detected waves resulting from at least a second fluid oscillator device frequency range. In certain instances, analysis of the acoustic signals includes interpreting the acoustic signals to provide information about operational aspects of one or more components of the well system. In certain instances, the information provided may include information about an operational state of a combustor, such as an air/fuel ratio, a combustion temperature, a combustion efficiency, and/or other data. In certain instances, the analysis of the detected acoustic signals may include correlation of detected data to control data, for example, data related to an ideal operational state and/or a non-ideal operational state of the combustor.
A travel-time lapse between the generation of an acoustic signal by an acoustic source and the detection of the resulting sequence of reflected acoustic signals by an acoustic detector, in some implementations, provides a measure of the depths of the respective interfaces and/or formations from which the wavefield was reflected. The amplitudes of the reflected acoustic signals may be a function of the density and porosity of the respective interfaces from which the wavefields were reflected as well as the formations through which the wavefields propagated. The phase angle and frequency content of reflected acoustic signals may be influenced by formation fluids, subterranean resources, and/or other formation characteristics.
In some implementations, acoustic data can be used to monitor fluid migration, such as movement of a steam front and/or migration of resources (e.g., oil) in response to injected steam. In some implementations, acoustic data can be used to monitor and/or probe the integrity of the well system. For example, acoustic data may provide information about the presence of cracks and/or leaks in downhole equipment. In some implementations, acoustic data can be used to monitor operation of a steam generator.
FIG. 1A is a diagram illustrating an example well system 100 a. The example well system 100 includes a well bore 102 defined in a subterranean formation below ground surface 110. The well bore 102 is cased by a casing 108, which may be cemented in the well bore 102. In some cases, the well bore may be an open hole well bore 102, without the casing 108. The illustrated well bore 102 includes a vertical section and a horizontal section. However, a well bore can include a vertical wellbore without horizontal sections, or a well bore can include any combination of horizontal, vertical, curved, and/or slanted sections. In some cases, a well bore includes multiple parallel sections, for example, in a dual-well or SAGD configuration. Packers 152 isolate axial sections of the well bore, for example, by providing a seal to restrict fluid flow between the axial sections.
The subterranean formation includes multiple zones 112 a, 112 b, and 112 c. The zones can include layered zones, and a given zone can include one or more layers and/or a portion thereof. The zones can include rock, minerals, and resources of various properties. For example, the zones can include porous rock, fractured rock, steam, oil, gas, coal, water, sand, and/or other materials. In some cases, acoustic data is used to identify properties of a zone.
The well system 100 a includes a working string 106 configured to reside in the well bore 102. The working string 106 terminates above the surface 110 at the well head 104. The working string 106 includes a tubular conduit configured to transfer materials into and/or out of the well bore 102. For example, the working string 106 can communicate fluid (e.g., steam or another type of heat transfer fluid) into or through a portion of the well bore 102. The working string 106 can be in fluid communication with a fluid supply source. Example fluid supply sources include a steam generator, a surface compressor, a boiler, an internal combustion engine and/or other combustion device, a natural gas and/or other pipeline, and/or a pressurized tank.
In the illustrated example, the working string 106 can include a fluid injection string to inject heated treatment fluid into the well bore 102. A number of different tools are provided in and/or attached to the working string 106. The system 100 a includes steam oscillator systems 118 a and 118 b to oscillate a flow of fluid into the well bore 102. A fluid injection string can include any number of steam oscillator systems 118, and in some cases, a fluid injection string includes no fluid oscillator system 118. The illustrated working string 106 includes a steam generator 116 in fluid communication with the steam oscillator system 118. The steam generator 116 is a fluid supply system which can be installed at any location in the well system 100 a. For example, the steam generator 116 can be installed at any location in the well bore 102 or above the surface 110 external to the well bore 102. The example steam generator 116, a downhole steam generator, includes input feeds to receive input fluid from the surface 110. The example steam generator 116 heats the input fluid to produce steam and/or to heat another type of heat transfer fluid. In some implementations, heat is provided through one or more of a combustion process (e.g., combustion of fuel and oxygen), a non-combustion chemical process, electrical heating, and/or others. In some cases a fluid injection string can include one or more horns to generate acoustic signals. For example, a horn can include a tapered volume for generating, transferring and/or supporting acoustic signals.
The casing can include perforations in any subterranean region or zone. The illustrated casing 108 includes perforations 114 through which steam can be injected into the zone 112 a and/or 112 c. In some cases, steam is injected into the zone 112 a and/or 112 c through the perforations 114 at an oscillating flow rate. Additionally, resources (e.g., oil, gas, and/or others) and other materials (e.g., sand, water, and/or others) may be extracted from the zone of interest through the perforations 114. The casing 108 and/or the working string 106 can include a number of other systems and tools not illustrated in the figures. For example, the casing and/or the working string can include inflow control devices, sand screens, slotted liners and associated liner hangers, and/or other components.
The well system 102 also includes a control system that includes a controller 120, signal lines 124, and sensors 122 a, 122 b, 122 c, 122 d, 122 e, 122 f, 122 g, 122 h (collectively, sensors 122). The illustrated sensors 122 detect acoustic signals. Example sensors 122 include geophones, hydrophones, pressure transducers, or other detection devices at the surface 110, in the well bore 102, or in another well bore (e.g., an adjacent, nearby and/or other well bore). In some implementations, the control system includes additional sensors that detect physical properties other than acoustic signals. For example, the control system can also include sensors that detect temperature, pressure, flow rate, current, voltage, and/or others. In some cases, the control system also includes a monitor 126. The monitor 126 can display data related to the well system 100 a. For example, the monitor 126 can include an LCD, a CRT, or any other device for presenting graphical information. The control system includes one or more signal lines 124. The signal lines 124 allow communication among the components of the well system 100 a. For example, the sensors can communicate data to the controller 120 via the signal lines 124, and the controller 120 can communicate control signals to the steam generator 116 and/or the steam oscillator system 118 via the signal lines 124. In certain cases, sensors 122 communicate with the controller 120 using dedicated signal lines. In certain cases, the sensors 122 communicate over shared signal lines. In some implementations, the signal lines include metal conductors, fiber optics, and/or other types of coupling media. In some implementations, some or all of the signal lines 124 may be omitted. For example, the sensors 122 may communicate data to the surface 110 using electromagnetic downlink coupling, that does not require downhole control lines. Electromagnetic downlink coupling may include low frequency electromagnetic telemetry.
Sensors 122 can be located at a variety of positions in the well system 100 a. In the illustrated example, the sensor 122 a is installed above the surface 110 proximate the well head 104; the sensor 122 b is installed above the surface 110 at a distance from the well head 104; the sensor 122 c is installed below the surface 110 at a distance from the well head 104; the sensor 122 d is installed in the well bore 102 at a radial position proximate the casing 108 and a longitudinal position between the surface 110 and the steam oscillator system 118; the sensor 122 e is installed in the well bore 102 at a radial position proximate the working string 106 and a longitudinal position between the surface 110 and the steam oscillator system 118; the sensor 122 f is installed proximate the steam generator system 116; the sensor 122 g is installed proximate the steam oscillator system 118 a; the sensor 122 h is installed in the well bore 102 at a radial position proximate the casing 108 and a longitudinal position beyond the steam oscillator system 118 in the well bore 102; the sensor 122 l is installed proximate the steam oscillator system 118 b. Sensors may be installed in additional and/or alternative locations, not illustrated in FIG. 1A.
One or more of the sensors 122 can be integrated into the structure of one or more well system components. For example, the sensor 122 f can be integrated into the structure of the steam generator 116. Alternatively, the sensor 122 f can be implemented as a separate acoustic-sensing device installed proximate the steam generator 116. As another example, the sensor 122 g can be installed proximate the steam generator 118 a, or the sensor 122 g can be integrated into the structure of the steam generator 118 a. In some cases, the well system 100 a includes multiple well bores and one or more sensors can be installed in a well bore other than the well bore 102, as illustrated in FIG. 1C. For example, the sensor 122 c in FIG. 1A can be integrated into the structure of a well system component installed in a well bore other than the well bore 102. In other cases, the sensor 122 c can be installed below the surface 110 by another technique. A sensor installed proximate the fluid injection string can be used to detect a baseline acoustic signal from an acoustic source. For example, the sensor 122 g can be used to detect a baseline acoustic signal from the steam oscillator system 118 a, and the baseline acoustic signal can be compared to an acoustic signal detected at a different sensor 122 located at a greater distance from the steam oscillator system 118 a (e.g., the sensor 122 b).
FIG. 1B is a detailed view of a portion of a well system 100 b. As illustrated in FIG. 1B, the steam oscillator system 118 communicates steam 154 a and/or other heat transfer fluids into the well bore 102 below a packer 152. The packer 152 isolates longitudinal sections of the well bore 102 and prevents the steam 154 a from flowing toward the surface 110 within the well bore 102. The steam 154 a penetrates the zone 112 through the perforations 114 below the packer 152. The steam 154 b that has entered the subterranean formation from the well bore 102 can reduce viscosity of fluid resources 156 and/or otherwise stimulate production from the zone. As steam flows into the zone 112, a steam front 158 migrates through the zone 112. In some cases, acoustic data can be used to monitor migration of the steam front 158. For example, the steam front can represent an interface between the steam 154 b and the fluid resources 156. The steam front can therefore represent a change in acoustic impedance that can be detected by processing acoustic signals reflected and/or transmitted by the steam front 158.
The well system 100 a includes control hardware 140 to control the operation of well system components. The control hardware 140 can communicate with components of the well system 100 a including control valves 150 a, 150 b, and 150 c. For example, the control hardware 140 can communicate with the control valve 150 a through a control line 144 a, the control hardware 140 can communicate with the control valve 150 b through a control line 144 b, and the control hardware 140 can communicate with the control valve 150 c through a control line 144 c. The control lines 144 a, 144 b, and 144 c can be implemented as electrical control lines, hydraulic control lines, fiberoptic control lines, and/or another type of control line.
The control valves 150 a, 150 b, and 150 c can be implemented as variable flow control valves that control a flow rate of a fluid through a conduit. The control valves 150 a, 150 b, and 150 c can be used to control operation of one or more well system components. For example, the working string 106 can communicate an oxidant fluid, such as air, oxygen, and/or other oxidant, to the steam generator 116 at a flow rate controlled by the control valve 150 a; a conduit 146 can communicate fuel, such as liquid gasoline, natural gas, propane, and/or other fuel, to the steam generator 116 at a flow rate controlled by the control valve 150 b; and a conduit 148 can communicate heat transfer fluid, such as water, steam, synthetic fluid, and/or other heat transfer fluid, to the steam generator 116 at a flow rate controlled by the control valve 150 c. The control hardware 140 can send signals to the control valves 150 a, 150 b, and 150 c based on data received from the controller 120.
In one aspect of operation, the steam generator 116 generates steam based on materials received through the working string 106 and the conduits 146 and 148. The steam generator 116 includes a combustor 182 that can combust an air fuel mixture. In some cases, operation of the combustor 182 is controlled and/or modified base on acoustic signals detected by a sensor, such as sensor 122 f or another sensor. The steam generator 116 also generates acoustic signals during operation. For example, in a steam generator 116 that generates heat via combustion, the combustion can generate acoustic signals that can be used to characterize the combustion. The acoustic signals are detected by one or more of the sensors 122 f, 122 g, 122 h and/or another sensor. The detected acoustic data are communicated to the controller 120, and the controller 120 analyzes the acoustic data, alone or in combination with data from other sensors. For example, the controller 120 can use information from one or more temperature sensors, one or more pressure sensors, one or more flow meters, and/or other sensors or measurement devices. In certain instances, the temperature sensors can measure the temperature of combustion, the temperature of the heated fluid generated by the steam generator 116, the temperature in the well bore about the steam generator 116, the temperature of the air, oxidant and/or heat transfer fluid, and/or other temperatures. In certain instances, the pressure sensors can measure the pressure in the combustion chamber of the steam generator 116, the pressure in the well bore about the steam generator 116, the pressure of the air, oxidant and/or heat transfer fluid, and/or other pressures. In certain instances, the flow meters can measure the flow of air, oxidant and/or heat transfer fluid into the steam generator 116, the flow of heated fluid out of the steam generator 116 and/or other flows. In some cases, the acoustic signal generated by the steam generator 116 and detected by the sensors 122 provides information about an operating state of the steam generator 116, such as an ideal or a non-ideal operating state.
Certain operating conditions of the steam generator 116 produce instability in the combustion of the fuel and oxidant. For example, introducing heat transfer fluid into the steam generator 116 at too high of a rate can tend to quench the combustion of the fuel and oxidant. The quenching or near quenching can cause combustion that is not consistent, steady and strong, i.e., instability. In another example, introducing a fuel-to-oxidant ratio that is too high (i.e., rich) can cause similar instability. A combustion instability will typically produce a non-uniform acoustic signal, for example, that sputters. Examples of non-ideal operating states of a combustor that can be identified and/or diagnosed based on acoustic data include a lean burn state (e.g., combustion of oxidant/fuel mixture having an oxidant-to-fuel ratio higher than that of a stoichiometric oxidant/fuel mixture), a rich burn state (e.g., combustion of oxidant/fuel mixture having an oxidant-to-fuel ratio lower than that of a stoichiometric oxidant/fuel mixture), a flame out with re-ignition state (e.g., combustion reaction temporarily stops or slows significantly), and others. In some implementations, acoustic data can be interpreted to verify ignition in a combustor. In some implementations, partial quenching of a combustion reaction and/or other instabilities can produce shock waves, and the shock waves can be interpreted to identify the quenching and/or other instabilities.
The controller 120 can be programmed to recognize acoustic data indicative of a non-ideal operating state of a well system component. In some cases, the controller 120 can be programmed to identify the cause of the non-ideal operating state of the steam generator 116 based on the detected acoustic data. For example, different types of non-ideal operating states may make different acoustic signals and the controller 120 can be programmed to identify the different acoustic signals and determine what non-ideal operating state is occurring. In some cases, the controller 120, can be programmed to generate instructions for altering the operation of the steam generator 116 based on an identified cause of a non-ideal operating state. The instructions can be communicated directly to the steam generator 116 via the signal lines 124, and/or the instructions can be communicated to the control hardware 140. Based on the received instructions, the steam generator 116 may modify an operating parameter and/or the control hardware 140 may manipulate a control valve 150 a, 150 b, and/or 150 c. For example, in some cases an air to fuel ratio in a combustor may be modified based on the detected acoustic signals. As another example, a flow rate of treatment fluid into the steam generator 116 can be adjusted based on the detected acoustic signals.
In some instances, it may be difficult or impractical to determine the non-ideal operating state from the acoustic signal, other than that a non-ideal operating state exists. The controller 120 may be programmed to generate instructions to adjust different aspects of the steam generator 116 (e.g., the fuel, oxidant, treatment fluid) in a trial and error type approach until the non-ideal operating state subsides. For example, upon recognizing the existence of an unidentified non-ideal operating state, the controller 120 may make adjustments to the ratio of fuel and oxidant and note whether the non-ideal operating state subsides. If not, the controller 120 may then adjust the amount of fuel and oxidant and note whether the non-ideal operating state subsides. If not, the controller 120 may then adjust the treatment fluid flow rate, and so on, adjusting different parameters until it determines an adjustment that reduces or eliminates the non-ideal operating state. The controller 120 can additionally use information from other sensors, such as oxygen sensors, temperature sensors, flow sensors, pressure sensors, and/or other sensors, together with the information from the acoustic signal in generating instructions for operating the steam generator 116.
In one aspect of operation, the steam oscillator system 118 oscillates heat transfer fluid into the well bore 102, and the steam oscillator system 118 generates acoustic signals during operation. In some cases, the steam oscillator system 118 is tuned to generate acoustic signals having specified properties. For example, the steam oscillator system 118 may include one or more steam whistles to generate acoustic signals having one or more specified frequencies. In some cases, oscillation frequencies of the steam oscillator system 118 are matched to resonant frequencies of the well bore 102, regions of the well bore 102, components of the well system 100 b, and/or regions of the subterranean formation. Generating acoustic signals at a resonance frequency can increase and/or optimize an acoustic response, in some cases. Driving an object at the object's resonance frequency may increase and/or maximize the energy transferred to the object, and therefore increase and/or maximize the acoustic response generated by the object. For example, a cavity formed by the casing 108 below the oscillator system 118 will have a characteristic resonance frequency. An acoustic signal having a frequency sufficiently close to the resonance frequency of the cavity 108 can stimulate a high and/or maximum pressure amplitude excursion within the cavity 108. There may also be an acoustic resonance frequency associated with the subterranean formation and/or regions or materials within the subterranean formation. Higher fluid velocities and/or pressure amplitudes may be produced within the formation, for example, when the steam oscillator system 118 generates acoustic signals at or near the resonance frequencies of the formation. These higher fluid velocities and/or pressure amplitudes may improve fluid injectivity and/or reduce steam channeling. The acoustic signals are detected by one or more of the sensors 122 f, 122 g, 122 h and/or another sensor. In some cases, the acoustic signals interact with the subterranean formation and/or a component of the well system 100 a before they are detected. The detected acoustic data is communicated to the controller 120, and the controller 120 analyzes the acoustic data, alone or in combination with other information. For example, the controller 120 can use information from one or more temperature sensors, one or more pressure sensors, one or more flow meters, and/or other sensors or measurement devices. In certain instances, the temperature sensors can measure the temperature of combustion, the temperature of the heated fluid generated by the steam generator 116, the temperature in the well bore about the steam generator 116, the temperature of the air, oxidant and/or heat transfer fluid, and/or other temperatures. In certain instances, the pressure sensors can measure the pressure in the combustion chamber of the steam generator 116, the pressure in the well bore about the steam generator 116, the pressure of the air, oxidant and/or heat transfer fluid, and/or other pressures. In certain instances, the flow meters can measure the flow of air, oxidant and/or heat transfer fluid into the steam generator 116, the flow of heated fluid out of the steam generator 116 and/or other flows. In some cases, the acoustic data detected by the sensors 122 provide information related to resources in the subterranean formation. In some cases the location of an interface between two or more different materials can be identified based on detected acoustic signals. For example, an interface between oil and water or another material may be identified.
FIG. 1C illustrates an example well system 100 c. The example well system 100 c includes a working string 106 installed in a well bore 102. The working string 106 includes a fluid injection string. The fluid injection string includes a steam generator 116, a control valve 150 d, conduits 180 a, 180 b, 180 c, 180 d, and whistles 302 a and 302 b. The conduits can be pipes, tubes, or hoses. The control valve 150 d can selectively communicate fluid from the conduit 180 a into any combination of the conduits 180 b, 180 c, and 180 d. The control valve 150 d can receive a control signal through the control line 144 d. For example the control signal can be generated by control hardware 140 or a controller 120, and the control valve 150 d can select, based on the control signal, one of, none of, or multiple of the conduits 180 b, 180 c, and 180 d. The conduit 180 d can communicate fluid to a third device (not shown), or the conduit 180 d can serve as a bypass to communicate fluid directly into the well bore 102.
The whistles 302 are described in greater detail below with regard to FIGS. 3A and 3B. Either or both of the whistles 302 can be replaced with a different type of fluid oscillator device, such as the fluid oscillator device 309 a of FIG. 3C. The well system 100 c can include a number of whistles and/or other fluid oscillator devices in fluid communication with the steam generator 116. The whistles can be positioned proximate one another or at a distance from one another (e.g., 10 feet, 100 feet, 1000 feet, or another distance). The whistles can be tuned to different acoustic frequencies, or the whistles can all be tuned to generate the same acoustic frequencies.
In one aspect of operation, the steam generator 116 receives unheated treatment fluid, heats the treatment fluid, and outputs heated treatment fluid to the conduit 180 a. During a first time period, the heated treatment fluid is communicated to the whistle 302 a, and the whistle 302 a generates a first acoustic signal having a first frequency content (which may be one or many different frequencies). During a second time period, the heated treatment fluid is communicated to the whistle 302 a, and the whistle 302 a generates a second acoustic signal having the first and/or a second frequency content. The second time period may be before, after, or overlapping the first time period. During a third time period, the heated treatment fluid is communicated into the well bore 102 through the conduit 180 d. The second time period may be before, after, or overlapping the first and/or second time periods. The steam generator 116 may also generate a third acoustic signal during the first, second, and/or third time periods.
Any of the first, second, and or third acoustic signals can be detected by the sensors 122 f, 122 g, 122 h, 122 l, and/or any of the other sensors illustrated in FIG. 1A, 1B, or 1C. Acoustic signals detected by a sensor can be processed to identify a portion of the first, second, and/or third acoustic signals. For example, detected acoustic signals can be processed to identify a direct signal, a secondary signal, a reflected signal, a transmitted signal, a baseline signal, and/or any other portion of an acoustic signal generated in connection with injecting heated treatment fluid into the well. The identified portions of the detected acoustic signals can be compared, filtered, modified, convolved, transformed and/or processed in another manner.
Based on the acoustic signal processing, information can be determined about at least one of the fluid injection string, the well, or the subterranean zone. The determined information can include information related to at least one of description of the subterranean formation, integrity of the well, or operation of the fluid injection string. The information related to description of the subterranean formation can include information related to at least one of a location of a fluid interface, a movement of a fluid interface, or other information. The information related to integrity of the well can include information related to at least one of a leak in a component of the well, a leak in a tool installed in the well, a flow obstruction in the well, a flow obstruction in a tool installed in the well, or another aspect. The information related to operation of the fluid injection string can include information related to at least one of an air to fuel ratio, a combustion temperature, a combustion efficiency, or a fluid composition. The controller 120 can modify at least one aspect of operation of the fluid injection string based on the information provided by the analysis of acoustic signals.
FIG. 1D illustrates example operational aspects of a well system 100 d. The illustrated well system 100 b includes a first well bore 102 a and a second well bore 102 b. The well bore 102 a can include the same components as the well bore 102 of FIG. 1A or 1B. The well bore 102 b may also include the same and/or different components as are included in well bores 102 of FIG. 1A or 1B. For example, the well bore 102 b can optionally include the working string 106 b. The well bore 102 b includes sensors 122 j and 122 k installed below the surface 110. The well system 100 d also includes a sensor 122 i installed above the surface 110. The zone of interest 112 includes two different regions 172 a and 172 b separated by a boundary 170. In the illustrated example, the region 172 a resides above the horizontal boundary 170 and the region 172 b resides below the horizontal boundary 170. However, in other implementations, the boundary 170 can have any type of configuration, including vertical, horizontal, slanted, curved, tortuous, and others. As an example, the boundary 170 may represent an interface between a region 172 a composed primarily of oil and/or rock and a region 172 b composed primarily of steam and/or rock. In some cases, properties of the boundary 170, the region 172 a, and/or the region 172 b can be identified based on acoustic signals generated by components of the well system 100 b. The boundary 170 can represent a change in acoustic impedance.
Example acoustic signals are represented in FIG. 1D by arrows 160 a, 160 b, 160 c, 160 d, 160 e, and 160 f. Arrows 160 a and 160 b illustrate acoustic signals generated by the steam oscillation system 118. Arrow 160 b illustrates a portion of the acoustic signals that interact with the region 172 b and are detected by the sensor 122 k. Arrow 160 a illustrates a portion of the acoustic signals that interact with the region 172 b and the boundary 170. When the acoustic signals reach the boundary 170, a portion of the acoustic signals are transmitted into the region 172 a, as illustrated by arrows 160 e and 160 f. Arrow 160 f illustrates a portion of the propagated acoustic signals detected below the surface 110 by the sensor 122 j, and arrow 160 e illustrates a portion of the propagated acoustic signals detected above the surface 110 by the sensor 122 i. Some of the acoustic signals are reflected by the boundary 170, as illustrated by the arrows 160 c and 160 d. For example, the acoustic signals may be reflected due to a difference in acoustic impedance between the two regions 172 a and 172 b. Arrow 160 c illustrates a portion of the reflected acoustic signals detected by the sensor 122 k in the well bore 102 b, and arrow 160 d illustrates a portion of the reflected acoustic signals detected by the sensor 122 h in the well bore 102 a. The arrows 160 a, 160 b, 160 c, 160 d, 160 e, and 160 f illustrate example acoustic signals and are not intended to imply or define any limitation on the generation and/or detection of acoustic signals in a well system.
FIG. 2 is a block diagram illustrating detection and analysis of acoustic signals generated in a well system. The example well system 200 includes multiple system components, such as the components illustrated in FIG. 1A, such as a completion string, a steam generator, a fluid oscillator system, production packers, inflow control devices, and other components. Some of the well system components may be installed above the ground surface, below the ground surface, inside of a well bore, outside of the well bore, and/or at other locations. One or more of the well system components includes an acoustic source 208; one or more of the well system components includes an interaction medium 210 a; one or more of the well system components includes an acoustic detector 212; and one or more of the well system components includes an acoustic signal analyzer 214. The well system 200 may also include additional well system components 206.
As illustrated in FIG. 2, acoustic signals generated by the acoustic source 208 are detected by the acoustic detector 212. In some cases, for example, when the acoustic detector 212 is installed adjacent to the acoustic source 208, the acoustic signals generated by the acoustic source 208 do not traverse an interaction medium before they are detected by the acoustic detector 212. In some cases, for example, when the acoustic detector and the acoustic source 208 are both installed in the same well bore, the acoustic signals generated by the acoustic source 208 interact with an interaction medium 210 a within the well system 200 before reaching the acoustic detector 212. In some cases, for example, when the acoustic detector 212 is installed at the surface or in a different well bore than the acoustic source 208, acoustic signals generated by the acoustic source 208 interact with an external interaction medium 210 b before reaching the acoustic detector 212. The external interaction medium 210 b can include all or part of a subterranean formation, a zone of interest, and/or above-surface media. The acoustic signal analyzer 214 analyzes the detected acoustic signals. The acoustic source 208 and/or other system components 206 may be modified or otherwise controlled based on information provided by the acoustic signal analyzer 214. For example, a valve or a switch may be reconfigured based on information provided by the acoustic signal analyzer 214.
In some cases, the acoustic signals interact with the interaction medium 210 a before the acoustic signals are detected by the acoustic detector 212. For example, as the acoustic signals propagate through a well bore to a sensor installed in the well bore, the acoustic signals can interact with fluids, tools, and/or other media in the well bore.
In some cases, the acoustic signals interact with the interaction medium 210 b before the acoustic signals are detected by the acoustic detector 212. For example, as the acoustic signals propagate through a subterranean formation to a sensor, the acoustic signals can interact with fluids, solids, and/or other types of media in the formation. The propagation of acoustic signals through a material may depend, among other things, on the acoustic impedance of the material. For example, acoustic signals may travel faster through some types of rock than through oil or water, since some types of rock are more dense than oil or water. The propagation of sound through the material may also depend on other properties of the material, such as temperature, pressure, and others. Consequently, the amount of time needed for an acoustic signal to propagate through a given material may depend on the properties of the given material. Furthermore, some materials may absorb, or damp, acoustic signals more significantly than other materials. Therefore, the amplitude loss of an acoustic signal as the acoustic signal is propagated through a given material may depend on the properties of the material.
In some cases, a subterranean location includes multiple zones, where each zone has a characteristic property (e.g., a characteristic related to acoustic impedance) that is substantially homogeneous throughout the zone. For example, a zone may have a substantially homogeneous material composition and mass density throughout the zone, and/or a zone may have a substantially homogeneous pressure throughout the zone. An interface between two zones represents a transition from a zone having a first characteristic property to a zone having a second characteristic property. An interface can be embodied, in some cases, as a well-defined boundary, for example, between two different types of rock. In other cases, an interface can be represented as a more nebulous transition region, for example, a region of mud between water zone and a sand zone.
When acoustic signals impinge an interface (e.g., where there is a change in acoustic impedance), a portion of the acoustic signals may be reflected and a portion of the acoustic signals may be transmitted across the interface. In some cases, the amplitude of the transmitted portion and the amplitude of the reflected portion are determined by the differences in the properties of the two zones that share the interface. For example, an interface between two zones having a significant difference in mass density may cause a significant portion of the incident acoustic signal to be reflected and only a small portion of the incident acoustic signal to be transmitted across the interface. However, an interface where the change in mass density is very small may cause a more significant portion of the incident acoustic signal to be transmitted across the interface. In some cases, multiple sensors can be used to detect the transmitted and reflected signals. For example, a first sensor can detect a direct signal that has been transmitted across an interface and a second sensor can detect a reflected signal that has been reflected at the interface.
The acoustic detector 212 a can include various sensors and/or transducers for converting acoustic signals to electrical signals (e.g. voltage, current, or others). In some cases, the human ear or touch to a surface structure may be sufficient to detect at least qualitatively a characteristic indicative of the parameter of interest.
The acoustic signal analyzer 214 can include software, hardware, and/or firmware configured to process and/or interpret acoustic signals. The acoustic signal analyzer 214 can be implemented as multiple software modules on one or more computing devices. The acoustic signal analyzer 214 can be implemented as an acoustic network analyzer to determine acoustic impedance at a variety of acoustic frequencies. The acoustic signal analyzer 214 can apply a variety of acoustic signal processing techniques, such as filtering, transforming, convolving, and others. The acoustic signal analyzer 214 can modify operation of or reconfigure the acoustic signal source 208 and/or another wellbore system component 206 based on the analysis of the acoustic signals.
FIGS. 3A and 3B illustrate an example steam whistle assembly 302 that includes a single steam whistle 304. The steam whistle assembly 302 can be included, for example, as a component of the steam oscillation systems 118 a or 118 b of FIG. 1A. The steam whistle assembly 302 includes a housing that defines two axial steam inflow paths and a cavity for the steam whistle 304. FIG. 3A is a side view of the steam whistle assembly 302. FIG. 3B is a cross-sectional side view of the steam whistle assembly 302 taken along axis 3B-3B of FIG. 3A.
As shown in FIG. 3B, the steam whistle 304 includes an inner surface that defines an inlet 306, an outlet 308, and a chamber 303. The steam whistle 304 can be implemented with no moving parts. The steam whistle 304 has a substantially static configuration to produce an oscillatory flow of heat transfer fluid through the outlet 308. For example, during operation the flow rate of steam through the outlet 308 (e.g., volume of steam per unit time) can oscillate over time. The oscillatory flow of heat transfer fluid may be generated by pressure oscillations in the chamber 303. The pressure oscillations may produce acoustic signals in a compressible heat transfer fluid. In some cases, the acoustic signals can be transmitted from the well bore 102 into the zone 112. For example, the acoustic signals can propagate through and interact with a subterranean formation and the resources therein. In some instances, the volume of the chamber 303 can be adjusted, for example, with an adjustable piston in the chamber 303 (not shown), to allow adjustment of the frequency of the oscillations.
During operation, steam flows into the steam whistle 304 through the inlet 306. The incoming steam strikes the edge 305, and the steam is split with a substantial portion flowing into the chamber 303. As steam flows into the chamber 303, the pressure of the steam in the chamber 303 increases. Due to the pressure increase in the chamber 303, steam inside the chamber 303 begins to flow out of the steam whistle 304 through the outlet 308. The flow of steam from the chamber 303 through the outlet 308 perturbs the flow of steam from the inlet 306, and at least a portion of the steam flowing from the inlet 306 begins to flow directly through the outlet 308 rather than into the chamber 303. As a result, the pressure of the steam in the chamber 303 decreases. Due to the pressure decrease in the chamber 303, the flow of steam from the inlet 306 shifts again and begins to flow into the chamber 303. The cyclic increase and subsequent decrease of the pressure of steam in the chamber 303 continues. In this manner, the pressure of the steam in the chamber 303 oscillates over time, and accordingly, the flow of steam through the outlet 308 oscillates over time.
FIG. 3C is a cross-sectional view of an example sub 307 that includes three steam oscillator devices 309 a, 309 b, and 309 c. For example, the sub 307 may be included in the steam oscillator system 118 of FIG. 1A. Each of the three steam oscillator devices 309 a, 309 b, and 309 c can inject heat transfer fluid into a well bore at a different axial position. The steam oscillator devices 309 a, 309 b, and 309 c operate in a static configuration to oscillate the flow of heat transfer fluid into the well bore. Devices 309 a and 309 b define outlets 314 that direct heat transfer fluid in a radial direction. Device 309 c defines outlets 314 that direct heat transfer fluid in a substantially axial direction.
The example steam oscillator device 309 a includes an interior surface that defines an interior volume of the steam oscillator device 309 a. The interior surface defines an inlet 310, two feedback flow paths 312 a, 312 b, two outlet flow paths 314 a, 314 b, a primary chamber 316, and a secondary chamber 318. The primary chamber 316 is bounded by a portion of the interior surface that includes two diverging side walls. The feedback flow paths 312 extend from the broad end of the primary chamber 316 to the narrow end of the primary chamber 316, near the inlet 310. The outlet flow paths 314 a, 314 b extend from the feedback flow paths 312 a, 312 b, respectively. The secondary chamber 318 extends from the broad end of the primary chamber 316. The secondary chamber 318 is bounded by a portion of the interior surface that includes two diverging sidewalls.
FIG. 4A is a flow chart illustrating an example process 400 for detecting acoustic signals generated from a well system. In some cases, the process 400 is implemented for detecting acoustic signals generated in connection with injecting heat treatment fluid into a well. Acoustic signals generated in connection with injecting heat treatment fluid into a well may include acoustic signals generated by a steam generator or another heated treatment fluid supply source, a steam whistle or another fluid oscillator device, and/or other tools. For example, the process 420 can be implemented in any of the well systems 100 a, 100 b, 100 c, and/or 100 d of FIGS. 1A-1D, and/or the well system 200 of FIG. 2. In various embodiments, the process 400 can include the same, fewer, or different operations implemented in the same or a different order.
At 402, acoustic signals are generated from a component of a well bore system. One or more acoustic signals may be generated by a fluid injection string. One or more acoustic signals may be generated in connection with injecting heated treatment fluid into the well bore. For example, a combustor of a steam generator, a fluid oscillator, and/or a whistle may generate an acoustic signal. The acoustic signals can be generated during a plurality of time periods. Each of a plurality of acoustic signals can be generated to have different properties. The properties can include, for example, one or more of frequency, pitch, amplitude, tone, phase, and/or others. The generated signals can include any combination of chirp-type signals, transient signals, frequency-sweep signals, random signals, pseudo-random signals, and/or others.
At 404, the acoustic signals are detected. For example, detecting the acoustic signal can include detecting a primary acoustic signal, a secondary acoustic signal, a reflected acoustic signal, a transmitted acoustic signal, a compression wave, a shear wave, and/or others.
At 406, the detected acoustic signals are analyzed. Analyzing the signals can include interpreting the detected acoustic signals. For example, the signals may be interpreted to gain information about at least one of the well, the subterranean formation, the fluid injection string. In some cases, a plurality of acoustic signals are detected, and the plurality of detected acoustic signals can be processed to identify a portion of the detected acoustic signal generated in connection with injecting heated treatment fluid into a well in a subterranean zone. Processing the detected acoustic signals can include filtering the signals to isolate a signal of interest, such as a portion of the signal generated by a fluid injection string. Processing the detected acoustic signals can include filtering out signals, such as acoustic signals generated in the subterranean zone and/or by a component of the well system other than a fluid injection string. The acoustic signals can be analyzed by comparing signals detected near an acoustic source with signals detected at a distance from the acoustic source. The compared signals can be signals generated during the same or different time periods. Processing the detected acoustic signals can include identifying a property of a portion of the detected acoustic signal. For example, the property can include at least one of amplitude, phase, or frequency. Processing the detected acoustic signal can include identifying a rising edge of an acoustic signal generated by a fluid oscillator device.
At 408, operation of a component of the well bore system is modified based on the analysis of the detected acoustic signals. For example, operation of a tool installed in the well can be modified based at least in part on the detected acoustic signal.
FIG. 4B is a flow chart illustrating an example process 420 for detecting acoustic signals generated from a well system. In some cases, the process 420 is implemented for detecting acoustic signals generated in connection with injecting heat treatment fluid into a well. Acoustic signals generated in connection with injecting heat treatment fluid into a well may include acoustic signals generated by a steam generator or another heated treatment fluid supply source, a steam whistle or another fluid oscillator device, and/or other tools. For example, the process 420 can be implemented in any of the well systems 100 a, 100 b, 100 c, and/or 100 d of FIGS. 1A-1D, and/or the well system 200 of FIG. 2. In various embodiments, the process 420 can include the same, fewer, or different operations implemented in the same or a different order.
At 422 a, a first acoustic signal is generated from a component of a well bore system. At 422 b, a second acoustic signal is generated from a component of a well bore system. The first and/or second acoustic signals can be generated in connection with injection of heated treatment fluid into a well. In some cases, the first acoustic signal comprises a first set of frequencies and the second acoustic signal comprises a second set of frequencies not included in the first set of frequencies. In some cases, the first acoustic signal is generated during a first time period and the second acoustic signal is generated during a second time period after the first time period and/or during the first time period.
At 424 a and 424 b, acoustic signals are detected. All or a portion of the acoustic signals can be detected by the same sensor or by multiple different sensors distributed in different locations in a well, above the surface, and/or in a subterranean zone.
At 426, the detected acoustic signals are analyzed to identify the first and second acoustic signals generated in connection with injecting heat treatment fluid into a well. For example, the detected acoustic signals can be processed to identify a first portion and/or a second portion of the detected acoustic signal generated in connection with injecting heated treatment fluid into a well in a subterranean zone.
At 428, the identified portions of the first and second acoustic signals are analyzed to identify properties of the well system or the subterranean formation. The identified portions of the detected acoustic signals can be used to determine information about at least one of the heated treatment fluid injecting or the subterranean zone. The identified portions of the detected acoustic signals can be used to identify movement of a fluid interface in the subterranean zone based at least in part on the first portion and the second portion. For example, identifying movement of a fluid interface can include identifying movement of a steam front. In some cases, analyzing the signals includes comparing properties of a first portion of signals to properties of a second portion of signals. In some cases, analyzing the signals includes identifying differences between the first portion and the second portion.
Some of the operations described in this specification, such as the analysis, filtering, digitization, and other operations based on the detected acoustic signals, can be implemented in digital electronic circuitry, or in computer software, firmware, or hardware. Some aspects can be implemented as one or more computer program products (e.g., in a machine readable storage device) to control the operation of data processing apparatus (e.g., a programmable processor, a computer, or multiple computers). A computer program (also known as a program, software, software application, or code) can be written in any form of programming language, including compiled or interpreted languages, and it can be deployed in any form, including as a stand alone program or as a module, component, subroutine, or other unit suitable for use in a computing environment. A computer program can be deployed to be executed on one computer or on multiple computers at one site or distributed across multiple sites and interconnected by a communication network.
A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made. Accordingly, other implementations are within the scope of the following claims.

Claims

1. A system, comprising:

a heated fluid injection string that injects heated treatment fluid into a well in a subterranean zone and generates an acoustic signal;

an acoustic detector that detects the acoustic signal; and

an acoustic signal analyzer that interprets the detected acoustic signal.

2. The system of claim 1, wherein the acoustic signal analyzer interprets the detected acoustic signal to determine information about at least one of the heated fluid injection string, the well, or the subterranean zone.

3. The system of claim 2, wherein the determined information comprises information related to at least one of description of the subterranean formation, integrity of the well, or operation of the fluid injection string.

4. The system of claim 3, wherein the information related to description of the subterranean formation comprises information related to at least one of a location of a fluid interface or a movement of a fluid interface.

5. The system of claim 3, wherein the information related to integrity of the well comprises information related to at least one of a leak in a component of the well, a leak in a tool installed in the well, a flow obstruction in the well, or a flow obstruction in a tool installed in the well.

6. The system of claim 3, wherein the information related to operation of the fluid injection string comprises information related to at least one of an air to fuel ratio, a combustion temperature, a combustion efficiency, or a fluid composition.

7. The system of claim 3, further comprising a controller configured to modify at least one aspect of operation of the fluid injection string based on the information provided by the acoustic signal analyzer.

8. The system of claim 1, wherein the fluid injection string comprises at least one of a fluid oscillator device, a whistle, or a horn.

9. The system of claim 1, wherein the acoustic detector comprises a plurality of sensors installed in a plurality of different locations.

10. The system of claim 1, wherein the acoustic detector comprises at least one of a sensor installed in the well, a sensor installed at a terranean surface, or a sensor installed in a different well.

11. The system of claim 1, wherein the acoustic detector comprises at least one sensor installed directly on at least one component of the fluid injection string.

12. The system of claim 1, wherein the fluid injection string comprises a steam generator installed in the well.

13. A method, comprising:

detecting an acoustic signal generated in connection with injecting heated treatment fluid into a well in a subterranean zone; and

interpreting the detected acoustic signal.

14. The method of claim 13, further comprising determining information about at least one of the heated treatment fluid injecting or the subterranean zone based at least in part on the interpretation of the detected acoustic signal.

15. The method of claim 13, further comprising injecting the heated treatment fluid into the well during a plurality of time periods to generate the detected acoustic signals.

16. The method of claim 13, wherein interpreting the detected acoustic signal comprises identifying a property of the detected acoustic signal, the property comprising at least one of amplitude, phase, or frequency.

17. The method of claim 13, further comprising modifying operation of a tool installed in the well based at least in part on the detected acoustic signal.

18. The method of claim 13, wherein interpreting the detected acoustic signal comprises identifying a rising edge of an acoustic signal generated by a fluid oscillator device.

19. The method of claim 13, wherein detecting the acoustic signal comprises detecting an acoustic signal generated by at least one of a steam generator, a fluid oscillator, a whistle, or a horn.

20. The method of claim 13, wherein detecting the acoustic signal comprises detecting a primary acoustic signal and a secondary acoustic signal.

21. The method of claim 13, wherein detecting the acoustic signal comprises at least one of detecting a reflected acoustic signal or detecting a transmitted acoustic signal.

22. The method of claim 13, wherein the acoustic signal comprises a first acoustic signal, the method further comprising:

detecting a second acoustic signal; and

interpreting the detected second acoustic signal

23. The method of claim 22, further comprising identifying movement of a fluid interface in the subterranean zone based at least in part on the interpretation of the first acoustic signal and the interpretation of the second acoustic signal.

24. The method of claim 22, wherein identifying movement of a fluid interface comprises identifying movement of a steam front.

25. The method of claim 22, further comprising comparing properties of the first acoustic signal to properties of the second acoustic signal.

26. The method of claim 22, further comprising identifying differences between the first acoustic signal and the second acoustic signal.

27. The method of claim 22, wherein the first acoustic signal is detected during a first time period and the second acoustic signal is detected during a second time period after the first time period.

28. The method of claim 22, wherein the first acoustic signal and the second acoustic signal are detected during the same time period.

29. The method of claim 22, wherein the first acoustic signal comprises a first set of frequencies and the second acoustic signal comprises a second set of frequencies not included in the first set of frequencies.

30. The method of claim 22, wherein the first acoustic signal is detected at a first location and the second acoustic signal is detected at a second location.

31. A system comprising:

a fluid injection string that generates an acoustic signal in connection with injection of heated treatment fluid into a well in a subterranean zone;

an acoustic detector that detects the acoustic signal; and

an acoustic signal analyzer that interprets the detected acoustic signal.

32. The system of claim 31, wherein the acoustic signal analyzer interprets the detected acoustic signal to determine information about at least one of the fluid injection string, the well, or the subterranean zone.

33. The system of claim 31, wherein the fluid injection string comprises a fluid oscillator device that includes an interior surface defining an interior volume of the fluid oscillator device, an inlet into the interior volume, and an outlet from the interior volume, the interior surface being static during operation to receive the heated treatment fluid into the interior volume through the inlet and to vary over time a flow rate of the heated treatment fluid from the interior volume through the outlet.

34. The system of claim 33, wherein the fluid injection string further comprises an additional fluid oscillator device and a valve to selectively communicate the heated treatment fluid to at least one of the fluid oscillator device or the additional fluid oscillator device.

35. The system of claim 34, wherein the fluid oscillator device comprises a first steam whistle configured to generate an acoustic signal comprising a first range of frequencies and the additional fluid oscillator device comprises a second steam whistle configured to generate an acoustic signal comprising a second range of frequencies.

36. The system of claim 34, further comprising a bypass conduit, the valve to selectively communicate the heated treatment fluid to at least one of the fluid oscillator device, the additional fluid oscillator device, or the bypass conduit.