ANGULAR RESPONSE COMPENSATION FOR VSP DSP

专利摘要:
A DAS VSP statement processing system is described. The system includes a DAS data collection system coupled to at least one optical fiber at least partially positioned within a wellbore and configured to either activate or passively listen to a source of seismic energy one or more times . The system also includes an information processing system connected to the DAS data collection system. A set of seismic data is received from the DAS data collection system recorded in a spatio-temporal domain. The seismic data set is transformed into the data set of the area of the radius parameter and interception time. The local apparent slope is determined for each seismic signal in the received seismic data set. The amplitude correction is performed for the seismic signals received using the slowness profile and the local apparent slope determined in the data set of the radius parameter and intercept time domain. The domain data set of the radius parameter and corrected interception time is retransformed into spatio-temporal domain.
公开号:FR3068479A1
申请号:FR1854478
申请日:2018-05-28
公开日:2019-01-04
发明作者:Xiang Wu；Mark Elliott Willis；Andreas Ellmauthaler
申请人:Halliburton Energy Services Inc；
IPC主号:

专利说明:


ANGLE RESPONSE COMPENSATION FOR VSP DSP
Authors: XIANG WU, MARK ELLIOTT WILLIS AND ANDREAS ELLMAUTHALER
TECHNICAL FIELD OF THE INVENTION
The embodiments disclosed here generally relate to the restoration of the amplitude of the vertical seismic profiling (VSP) surveys for the evaluation and monitoring of the training and, more particularly, the processes and processing and monitoring in real time of the surveys. VSP acquired using distributed acoustic detection (DAS) by optical fiber.
BACKGROUND OF THE INVENTION
Hydrocarbons, such as gas and petroleum, are generally obtained from underground formations which can be on land or offshore. The development of underground operations and the processes involved in recovering hydrocarbons from an underground formation are complex. Generally, underground operations involve a number of different steps such as, for example, drilling a wellbore through and / or in the underground formation at a desired wellsite, processing the drilling wells to optimize the production of hydrocarbons and the completion of the steps necessary to produce and process the hydrocarbons from the underground formation. Some or all of the steps may require and use measurements and other detected data to determine characteristics of the formation, hydrocarbon, equipment used in operations, etc.
An example of the detected data type includes seismic data in the form of VSP. VSP can refer to the measurement of seismic / acoustic energy in a wellbore from a seismic source on the surface of the wellbore (e.g., vibration truck, air gun and / or explosives). In some cases, fiber optic DAS can be used to acquire the seismic data necessary to form the VSP. DAS-based acoustic detection can use the Rayleigh backscattering property of an optical fiber core and can spatially detect disturbances that are distributed along a length of the fiber positioned inside a well. drilling. As is well known in the art, the seismic amplitude of DAS VSP geophysical data is distorted by various geophysical factors, such as, without limitation, spherical divergence, scattering, reflection / transmission, attenuation, etc. all of which occur in the training environment. In addition, the acquired seismic amplitude also suffers from the response of fiber optic cables, which are non-geophysical, and must be compensated for before any actual processing of the amplitude is carried out.
The ability to compensate for the response of fiber optic cables has direct relevance to the real-time and offline processing of VAS DAS data, particularly for real-time and offline processing integrated into a workflow. Therefore, there is an ongoing interest in developing improved survey control capable of recovering the seismic amplitude (i.e., from the distortion of the angular response) in the absence of further improvements equipment and / or in the absence of additional operational efforts.
BRIEF DESCRIPTION OF THE VARIOUS VIEWS OF THE FIGURES
For a more complete understanding of the disclosed embodiments, and for other advantages thereof, reference is now made to the following description taken in association with the attached figures, in which:
Figures IA to IC illustrate various illustrative examples of a DAS by optical fiber deployed in a wellbore according to the disclosed embodiments;
Figure 2 illustrates a block diagram of an exemplary information processing system, in accordance with the embodiments of this disclosure;
FIG. 3 illustrates an exemplary system for processing DAS VSP readings in real time in accordance with the particular embodiments of this disclosure;
Figure 4A illustrates the angle of incidence;
FIG. 4B illustrates the comparison of the response of the amplitude of the P waves of the incident angles of FIG. 4A for the geophone and DAS recording systems;
Figure 5 illustrates an example of the ray paths traveling through a flat-layer formation from a finely shifted seismic source to an optical fiber cable deployed in a wellbore;
FIG. 6 is a flowchart illustrating a real-time and offline processing method and the compensation of the angular response for the generation of a stack
Quality VSP in accordance with an embodiment of this disclosure;
Figure 7 illustrates an example of a processed synthetic DSP VSP data set from a 5-layer model illustrated in the figure;
Figure 8 is a diagram illustrating how the DAS VSP data set is divided into multiple band segments, in accordance with an embodiment of the present disclosure;
FIG. 9 is a synthetic example of a DAS VSP data set with an applied spherical divergence and an angular response which can be used to test the disclosed embodiments;
FIGS. 10A to 10D illustrate an approach making it possible to identify the incident angles in the domain τ - p, and the incident angles calculated with respect to the channel depth using a synthetic DSP VSP example, according to the modes of completion of this disclosure; and
FIG. 11 illustrates the comparison of the seismic signal amplitudes before and after the compensation of the angular response in accordance with the embodiments of the present invention, illustrated along an axis of the amplitude of the quadratic mean (RMS) and a depth axis.
DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENTS
The following discussion is presented to enable a specialist in the field to make and use the invention. Various modifications will be apparent to those skilled in the art, and the general principles described herein can be applied to embodiments and applications other than those detailed below, without departing from the spirit or scope of the disclosed embodiments, as defined here. The disclosed embodiments are not intended to be limited to the given embodiments illustrated, but should be given the widest scope in accordance with the principles and features disclosed herein.
The terms "couple" or "coupled" are intended to describe an indirect or direct connection. Thus, if a first device couples to a second device, this connection can be made through a direct connection, through an indirect electrical or mechanical connection through other devices and connections. The term "upstream" in the present context means along a flow path to the source of the flow, and the term "downstream" in the present context means along a flow path flow away from the source of the flow. The term "at the top of the hole" in this context means along the drill string or hole from a distal end to the surface, and the term "at the bottom of the hole" in this context means along the drill string or hole from the surface to the distal end.
It will be understood that the term "oil well drilling equipment" or "oil well drilling system" is not intended to limit the use of the equipment and methods described in these terms to the drilling of an oil well. The term also includes drilling for natural gas wells or oil wells in general. In addition, such wells can be used for production, monitoring or injection in relation to the recovery of hydrocarbons or other materials from the underground surface. This could also include geothermal wells intended to provide a source of heat energy rather than hydrocarbons.
As will be understood by those skilled in the art, aspects of this specification can be implemented as a system, method, or computer program product. Therefore, aspects of this disclosure may take the form of a fully hardware embodiment, a fully software embodiment (including firmware, resident software, microcode, etc.) or an embodiment combining software aspects and hardware which can all be generally referred to here as a "circuit", "module" or "system". In addition, aspects of this disclosure may take the form of a computer program product embodied in one or more computer readable media having computer readable program code implemented thereon.
In the context of this disclosure, an information processing system may include any device or grouping of devices which can operate to calculate, classify, process, transmit, receive, retrieve, generate, switch, store, display, manifest, detect , record, reproduce, manipulate or use any form of information, intelligence or data for monetary, scientific, control or other purposes. Examples of well known computer systems, environments and / or configurations which may be suitable for use with the information processing system include, without limitation, personal computer systems, server computer systems, thin clients, thick clients , portable or portable devices, multiprocessor systems, microprocessor based systems, set-top boxes, user programmable electronic components, network PCs, minicomputer systems, central computer systems and computing environments. distributed data processing which includes any of the foregoing systems or devices or any other suitable device which may vary in size, form, performance, functionality and price. The information processing system can include a variety of media readable by a computer system. Such carriers can be any available carrier that is accessible by the information processing system, and they include both volatile and non-volatile, removable and non-removable media. The information processing system may include media readable by a computer system in the form of a volatile memory, such as a random access memory (RAM) and / or a cache memory. The information processing system may also include other removable / non-removable, volatile / non-volatile storage media of the computer system, one or more processing resources such as a central processing unit ("CPU") or a hardware or software control logic and / or a ROM. Additional components of the information processing system may include one or more network ports for communication with external devices as well as various input and output (I / O) devices, such as a keyboard, mouse or a video screen. The information processing system may include one or more buses that operate to transmit communications between the various hardware components.
As noted above, the VSP can refer to the measurement of seismic / acoustic energy in a wellbore from a seismic source on the surface of the wellbore (e.g., a truck vibration, an air gun and / or explosives), or that located in a nearby wellbore (inter-well survey). Traditionally, these measurements can be recorded using tubing containing geophones and / or hydrophones generally approximately equally spaced. Using such equipment, it is generally possible to sample the seismic wave field at resolutions on the order of tens of meters. While hydrophones and geophones provide one-dimensional sensitivity (CI), they can be configured in pairs or trio for two-dimensional (2C) or three-dimensional (3C) sensitivity.
An alternative method of collecting VSP data may include the use of DAS techniques. In DAS VSP collection processes, the expensive geophone column is replaced by an optical fiber cable which can be, for example, cemented in the wall of the wellbore behind the casing or casing, or be temporarily placed in the wells (eg, inside a recoverable cable logging cable) with the drill string in place or removed from the wellbore. Therefore, DAS VSP collection techniques can allow seismic monitoring of the wellbore during operations such as stimulation and production, without intervention. In addition, DAS VSP data collection techniques can allow the collection of samples of seismic wave field data at resolutions of the order of one meter (unlike tens of meters with conventional geophones). In addition, DAS VSP data collection can occur over the entire well at one time, compared to geophones who are typically deployed in short networks covering only certain parts of the well at any given time. However, in the DAS approach the sensitivity constraint is a one-dimensional sensitivity constraint. This one-dimensional constraint can seriously limit the extent of the recovery of the amplitudes which are weakened by the angular response of the DAS.
The embodiments disclosed herein integrate the concept of real-time or offline data flow processing into a workflow that can recover the amplitude of the seismic signals affected by the angular response for the DAS VSP data set, providing improved control of the reading which must be applied at the level of different granularities. In particular, the method presented in this disclosure can also be applied to VSP geophone data, but it would be less meaningful with VSP geophone data since there could be multidimensional geophone data available for the data processing system. VSP enabling 3C processing methods which can better recover the amplitude of the seismic signals affected by the angular response. Therefore, various embodiments geared towards recovering the angular response are described below with respect to DAS VSP data only. However, a similar approach can also be applied to the VSP data of hydrophones and geophones. In order to facilitate a better understanding of the present disclosure, the following examples of certain embodiments are given. In no event should the following examples be construed as limiting, or defining, the scope of the disclosure. The embodiments of this disclosure and its advantages are better understood by referring to Figures IA to IC through Figure 12, in which like numbers are used to identify corresponding parts.
The embodiments of the present disclosure can be applicable to horizontal, vertical, deviated, multilateral wellbore, U-shaped, crossed, bridged connecting tube (dug around a fish blocked at mid-depth and back in the wellbore below), or otherwise non-linear wellbore in any type of underground formation. Certain embodiments may be applicable, for example, to logging data acquired by cable or smooth cable. Certain embodiments may be applicable to drilling wells under the sea and / or in deep water. The embodiments described below with respect to an implementation are not intended to be limiting.
Referring now to the figures, Figures IA to IC illustrate various illustrative examples of a fiber optic DAS deployed 103 in a wellbore according to the disclosed embodiments. One or more tubulars are positioned inside the wellbore 103 telescopically. As shown, the tubulars include a surface column 104 and a production column 106. Typically, the column is a tubular pipe, typically made of steel that maintains the integrity of the wellbore and well wall drill 103. The surface column 104 comprises the largest tubular and it is fixed in the well bore 103 by a layer of cement 114. The production column 106 is at least partially positioned inside the column surface 104 and can be fixed relative to the surface column 104 using a column support (not shown) and a layer of cement 114. The wellbore 103 also includes a casing 102 positioned inside of the production column 106. Other configurations and orientations of the tubulars inside the wellbore 103 are possible.
A DAS 100 system can be deployed with the wellbore 103. The DAS 100 system can include, among other things, a DAS 101 data collection system coupled to an optical fiber 108 which is at least partially positioned inside the well. drill 103. In one embodiment, as illustrated in FIG. 1C, the fiber 108 is positioned between the surface column 104 and the production column 106. The fiber 108 can be fixed in place between the surface column 104 and the production column 106 by couplers 110 so that it functions as a “permanent” seismic sensor. In another embodiment, illustrated in FIG. 1B, the fiber 108 can be fixed to the casing 102, for example, by couplers 110. In certain embodiments, the couplers 110 are cross coupling protectors located at the level of one joint in two of the casing 102. In yet another embodiment, illustrated in FIG. 1A, the fiber 108 can be lowered into the wellbore 103 through the internal hole of the casing 102 in a cable line module or smooth cable that can be removed, or positioned in any other suitable position.
It should be noted that any suitable number of DAS 100 systems can be placed adjacent to the wellbore 103. With the optical fiber 108 positioned inside a portion of the wellbore 103, the DAS 100 system may receive or otherwise obtain seismic data based on disturbances caused by a seismic source (not shown) using, for example, a DAS interrogation unit at the surface of the wellbore (not shown) . In one embodiment, the seismic energy source is a vibrator which scans a signal through a frequency range which includes a plurality of frequency bands. Some additional examples of seismic sources may include, without limitation, air cannons, weight drops, accelerated weight falls, marine vibrators, mortar cannons (e.g. dynamite), impact trucks, or any other suitable source of vibration to create seismic waves in the formation. As will be described in more detail below, the seismic data may correspond to the changes in the stress in the optical fiber 108 which are identified by detecting the phase changes in the backscattered light signals along the length of the optical fiber 108.
Although not illustrated in Figure 1A-1C, the disclosed DAS system 100 also includes an information processing system 200 (illustrated in Figure 2) positioned on the surface 112 of the earth. The information processing system 200 can be communication coupled to the DAS 101 data collection system through, for example, a wired or wireless connection. The information processing system 200 can receive the measurement in the form of a seismic data set originating from a DAS data collection system 101 and perform one or more actions which will be described in detail below. In addition, the information processing system 200 can receive a set of seismic data from a data center or a storage server in which the seismic data received or otherwise acquired by the DAS data collection system 101 were previously stored.
Modifications, additions or omissions may be made to Figures 1A to IC without departing from the scope of this disclosure. For example, the DAS data collection system 101 and the optical fiber 108 can be used during wired or smooth cable logging operations before fixing some or all of the tubulars inside the wellbore 103, and / or before the completion of borehole 103. As another example, multiple seismic sources can be used in association with the system
DAS 100. Additionally, components may be added to or removed from the DAS 100 system without departing from the scope of this disclosure.
FIG. 2 illustrates a block diagram of an exemplary information processing system 200, in accordance with the embodiments of the present disclosure. The information processing system 200 can be designed to receive seismic data sets originating from a DAS system and carry out one or more amplitude recovery methods which will be described in more detail below. The information processing system 200 can be used with different drilling and logging systems positioned at different locations.
The information processing system 200 includes a processor 204. The processor 204 may include, for example, a microprocessor, a microcontroller, a digital signal processor (DSP), an application-specific integrated circuit (ASIC), or any other digital or analog circuit configured to interpret and / or execute program instructions and / or process data. As illustrated, processor 204 is communicationally coupled to memory 206 and adapted to interpret and / or execute instructions or retrieved program data is stored in memory 206. The instructions or program data may constitute parts of the VSP survey control software module 208 for carrying out the procedures for controlling the VSP survey operation, as described here. The memory 206 may include any system, device or apparatus designed to contain and / or enclose one or more memory modules; for example, memory 206 may include read-only memory, random access memory, semiconductor memory, or disk memory. Each memory module may include any system, device or apparatus designed to retain program instructions and / or data for a period of time (eg, non-transient computer readable media). For example, the instructions coming from the control module of the VSP reading 208 can be retrieved and stored in the memory 206 for execution by a processor 204. In one embodiment of the present disclosure, the received seismic data sets acquired by a DAS system can be stored in a 210 database for long-term storage. In some embodiments, the information processing system may also include one or more displays or other input / output devices such that the information processed by the information processing system 200 (e.g., data seismic from a DAS system) can be sent to operators of drilling and logging equipment.
Modifications, additions or omissions can be made to Figure 2 without departing from the scope of this disclosure. For example, Figure 2 illustrates a given configuration of the components of the information processing system 200. However, any suitable configuration of the components can be used. For example, the components of the information processing system 200 can be implemented as physical or logical components. In addition, in certain embodiments, the functionality associated with the components of the information processing system 200 can be implemented in specialized circuits or components. In other embodiments, the functionality associated with the components of the information processing system 200 can be implemented in a circuit or configurable general-purpose components. For example, the components of the information processing system 200 can be implemented by configured computer program instructions.
As previously mentioned, the information processing system 200 can be coupled in communication with the DAS data collection system 101. FIG. 3 illustrates an example of a DAS data collection system 300 which is specifically designed to process DAS reports VSP in real time in accordance with the particular embodiments of this disclosure. The DAS VSP 300 processing system can be associated or otherwise incorporated into the DAS 100 system described above with reference to FIG. 1, with the optical fiber 108 at least partially positioned inside the wellbore 103. The processing system DAS VSP 300 can also be incorporated into other drilling, logging and completion systems that could benefit from this disclosure as will be understood by a specialist in the field. As will be explained, the DAS VSP 300 processing system may include a coherent single-pulse Rayleigh diffusion system with a compensation interferometer, but it is not intended to be limited to such a system. In particular, the DAS VSP 300 processing system can be used for phase-based detection events in a wellbore using Rayleigh's coherent backscatter measurements or can interrogate a fiber optic line containing a network of partial reflectors, eg a Bragg grating on fiber.
With reference to FIG. 3, the DAS VSP processing system 300 can comprise a pulse generator 314 coupled to a first coupler 310 using an optical fiber 312. The pulse generator 314 can be a laser, or a laser connected to at least one amplitude modulator, or a laser connected to at least one switching amplifier, ie, a semiconductor optical amplifier (SOA). The pulse generator 314 can be located at any location when performing underground operations. For example, in certain embodiments, the pulse generator 314 can be located at the surface 112 of the wellbore 103. The first coupler 310 can be a conventional welded type optical fiber separator, a circulator, a PLC optical fiber separator, or any other type of separator known to those skilled in the art having the benefit of this disclosure. The pulse generator 314 can be coupled to optical gain elements (not shown) to amplify the pulses generated therefrom. Examples of the optical gain elements include, without limitation, erbium-doped fiber amplifiers (EDFA) or semiconductor optical amplifiers (SOA).
The DAS VSP 300 processing system may include an interferometer 302. In some embodiments, the interferometer 302 includes a MachZehnder interferometer, but it is not intended to be limited thereto. For example, in some implementations, a Michelson interferometer or any other type of interferometer known to those skilled in the art having the benefit of this disclosure may also be used without departing from the scope of this disclosure. The interferometer 302 can include an upper interferometer arm 324, a lower interferometer arm 322, and a gauge 323 positioned on the lower interferometer arm 322. The interferometer 302 can be coupled to the first coupler 310 through a second coupler 308 and an optical fiber 332. The interferometer 302 can also be coupled to a photodetector assembly 320 of the system 300 through a third coupler 334 opposite the second coupler 308. The second coupler 308 and the third coupler 334 can be a separator of conventional welded type optical fiber, a PLC optical fiber separator, or any other type of optical separator known to those skilled in the art having the benefit of this disclosure. The photodetector assembly 320 may include optical and electronic components for associated signal processing (not shown). The photodetector assembly 320 can be a semiconductor electronic device that uses the photoelectric effect to transform light into electricity. The photodetector assembly 320 can be an avalanche photodiode or a PIN photodiode, but it is not intended to be limited thereto.
During the operation of the system 300, the pulse generator 314 can generate a first optical pulse 316 which is transmitted through the optical fiber 312 to the first coupler 310. The first coupler 310 can orient the first optical pulse
316 through the optical fiber 108, which can be coupled to the first coupler 310. Even if a linear deployment of the fiber cable is typical, different geometries can be used. For example, at least part of the optical fiber 108 can be arranged in coils 318. When the first optical pulse 316 travels through the optical fiber 108, the imperfections in the optical fiber 108 can cause the backscattering of part of the light along the optical fiber 108 due to Rayleigh scattering. The light scattered according to Rayleigh scattering is returned from each point along the optical fiber 108 along the length of the optical fiber 108 and is illustrated as backscattered light 328 in Figure 3. This effect of backscattering can be called Rayleigh backscattering. Fluctuations in the density in the optical fiber 108 can cause a loss of energy due to the scattered light, a _scat , with the following coefficient:
= T ^ n ^S V ² kT _f P (1) in which n represents the refractive index, p is the photoelastic coefficient of the optical fiber 108, k is the Boltzmann constant and β is the isothermal compressibility. T _f is a fictitious temperature, representing the temperature at which the density fluctuations are "frozen" in the material. The optical fiber 108 can be terminated with a low reflection device (not shown). In some implementations, the low reflection device (not shown) may be a coiled and fully bent fiber to violate Snell's law of total internal reflection so that all of the remaining energy is sent out of the fiber.
The backscattered light 328 can return through the optical fiber 108, until it reaches the second coupler 308. The first coupler 310 can be coupled to the second coupler 308 on one side by the optical fiber 332 so that the light 328 backscatter can pass from the first coupler 310 to the second coupler 308 through the optical fiber 332. The second coupler 308 can divide the backscattered light 328 based on the number of interferometer arms so that part of a any backscattered light 328 passing through the interferometer 320 travels through the upper interferometer arm 324 and another part travels through the lower interferometer arm 322. In other words, the second coupler 308 can split the light backscattered from the optical fiber 332 in a first backscattered pulse and a second backscattered pulse. The first backscattered pulse can be sent to the upper interferometer arm 324. The second backscattered pulse can be sent to the lower interferometer arm 322. These two parts can be reassociated at the third coupler 334, after they have left the interferometer 302, to form an interferometric signal.
The interferometer 302 can facilitate the generation of the interferometric signal through the relative phase shift variations between the light pulses in the upper interferometer arm 324 and the lower interferometer arm 322. Specifically, the gauge 323 can cause the length of the lower interferometer arm 322 is longer than the length of the upper interferometer arm 324. With different lengths between the two arms of the interferometer 302, the interferometric signal may include backscattered light from two positions along the fiber 108 so that a phase shift of the backlit light between the two different points along the fiber 108 can be identified in the interferometric signal. The distance between these points L can be half the length of the gauge 323 in the case of a Mach-Zehnder configuration, or equal to the length of the gauge in a configuration of Michelson interferometer.
When the DAS VSP 300 processing system is running, the interferometric signal will generally vary over time. Variations in the interferometric signal can identify stresses in the optical fiber 108 that are caused, for example, by seismic energy. Using the time of flight for the electrical pulse 316, the location of the stress along the optical fiber 316 and the time of its occurrence can be determined. If the optical fiber 108 is positioned inside a wellbore, the locations of the stresses in the fiber 108 can be correlated with the depths in the formation in order to associate the seismic energy with the locations in the formation and the wellbore.
In order to facilitate the identification of the constraints in the optical fiber 108, the interferometric signal can reach the photodetector assembly 320, where it can be transformed into an electrical signal. The photodetector assembly can provide an electrical signal proportional to the square of the sum of the two electric fields from the two arms of the interferometer. This signal is proportional to P (t) = Pi + P2 + 2 * Sqrt (PiP2) cos ((|) i- (|) 2) in which P _n represents the incident power to the photodetector coming from a given arm (1 or 2) and φ _η is the phase of the light coming from a given arm of the interferometer. The photodetector assembly 320 can transmit the electrical signal to the information processing system 200, which can process the electrical signal to identify stresses inside the fiber 108 and / or to transmit the data to a display and / or store them in a computer-readable medium. The photodetector assembly 320 and the information processing system 200 can be coupled in communication and / or mechanically. A first device can be coupled in communication to a second device if it is connected to the second device through a wired or wireless communication network which allows the transmission of information. Thus, the information processing system 200 can be located at the top of the hole, at the bottom of the hole, or at a remote location. The information processing system 200 can also be coupled in communication or mechanically to the pulse generator 314.
Modifications, additions or omissions may be made to Figure 3 without departing from the scope of this disclosure. For example, Figure 3 illustrates a given configuration of the components of system 300. However, any suitable configuration of the components can be used. For example, a compensation interferometer may be placed in a launch path (i.e., before the downward propagation of optical fiber 108) of the interrogation pulse to generate a pair of pulses which propagate downward from the optical fiber 108. In such embodiments, an interferometer is not required to interfere with the backscattered light from the pulses before being sent to the photodetector assembly. In one branch of the compensation interferometer in the path for launching the interrogation pulse, an additional length of fiber which is not present in the other branch (a length of gauge similar to gauge 323 of the figure 3) is used to delay one of the pulses. To integrate the phase detection of the backscattered light using the system 300, one of the two branches may include an optical frequency shift device (e.g., an acousto-optical modulator) for shifting the optical frequency of one of the pulses, while the other may include a gauge. This may allow the use of a single photodetector receiving the backscattered light to determine the relative phase of the backscattered light between two locations by examining the heterodyne beat signal from the mixing of light from different optical frequencies of the two pulses. question.
As another example, a system 300 can generate interferometric signals for analysis by the information processing system 200 in the absence of the use of a physical interferometer. For example, the system 300 can direct the backscattered light to the photodetector assembly 320 without first passing it through any interferometer, such as the interferometer 302 of FIG. 3. Furthermore, the backscattered light coming from the The interrogation pulse can be mixed with the light from the laser which initially provided the interrogation pulse. Thus, the light coming from the laser, the interrogation pulse and the backscattered signal can all be collected by the photodetector 320 and then analyzed by the information processing system 200. The light coming from each of these sources can be the same optical frequency in a homodyne phase demodulation system, or may have different optical frequencies in a heterodyne phase demodulator. This method of mixing the backscattered light with a local oscillator allows the phase of the backscattered light along the fiber to be measured relative to a reference light source.
In addition, in given embodiments, a continuously modulated interrogation signal may be issued in the fiber in place of a pulse (eg, pulse 316). For example, a phase, frequency or amplitude modulator depending on the laser can be used instead of a pulse generator (such as pulse generator 314) to send coded or interrogation signals. spectrum spread in the optical fiber 108 to allow distributed seismic detection using the information processing system 200.
As described above, the DAS can be used as a method of collecting seismic data from a formation. In given embodiments, the seismic data collected using DAS techniques can be VSP data. In order to collect DAS VSP data, a source that is activated on the surface of a wellbore can generate sound waves through the formation. Some examples of sources may include vibro-seismic, explosive sources (eg, dynamite), air cannons, impact trucks or any other vibration source suitable for collecting VSP data. The sound waves in the formation can cause stress changes in the optical fiber 108 in the fiber-optic cable of the DAS system, and these stress changes can be measured using DAS systems like those described above. In particular, the DAS VSP processing system 300 can send optical pulses into the optical fiber 108 at a given speed, parts of which can backscatter to the optical pulse source at various positions of the optical fiber 108, such as 'it is described above. These reflections can be measured at various times over finite times (which may coincide with the speed and duration of optical pulse generation) to measure stress changes in the fiber optic cable at various depths.
Each measurement captured by the DAS VSP 300 processing system can be called a “scan”. Even though the measurements described above are generated using a vibrator as a seismic source, the measurements and "scans" may relate to data collected from a single source that is powered up. Generally, after a certain period of source reset and / or listening time, powering up the source is repeated to start a new recording for the new source position. Thus, a typical raw measurement record includes both the sweep and the listening time. The characteristics of sound probes (e.g., amplitude and duration) from the fiber, which can be called acoustic activity, can be determined based, at least in part, on the measured stress changes. A scan can include seismic data in the form of acoustic activity for all measured depths of SAR along the wellbore over the finite time span. Seismic data within a scan can be demultiplexed to generate traces (or channels) of seismic data at various depths of data collection. Traces can indicate seismic data at a given depth in the wellbore during the sweep time. In various embodiments, each trace can be associated with different activation of the source by the DAS 300 data collection system. The properties of the formation can be determined using information from one or more scans (repetitions from the DAS 300 data collection system). For example, the speed of a formation (i.e., the speed of sound in the formation) can be determined. As another example, seismic data can be used to form underground images.
The DAS data collection process described above can be a more efficient way to collect seismic data compared to conventional geophones to collect the same information. The data collected with geophones can require significant time and a lot of physical effort compared to the DAS process described above. For example, the geophones must be physically raised and / or lowered and the source energized can then be repeated for each depth sample (channel) of the seismic data collected, which can take minutes or hours to complete. On the other hand, with the use of the DAS techniques as described, data for all the depths can be collected by sending optical pulses every few milliseconds for a few seconds in a fiber optic cable in a wellbore (without having to up or down the fiber optic cable). Advantageously, a source activation activates the acquisition of the entire set of seismic data covered by the optical fiber. As previously described, Rayleigh scattering from random impurities in the optical waveguide occurs when the optical waveguide is distorted by source-induced mechanical / seismic waves. The processing time of flight of laser pulses allows the fiber to reach a channel spacing of about 1 (one) meter, equivalent to the level of the VSP receiver. Thus, sample density is higher than conventional VSP, with data acquisition rates often as high as around 10 kHz.
However, unlike conventional measurements in 2C and 3C, DAS measurement techniques use straight-line deployed optical fiber cables, which are sensitive only along one dimension (direction of the fiber). Therefore, this approach does not allow for easy recovery of sound wave characteristics (i.e., amplitude) from different incident angles due to the absence of the other two components (dimensions). In addition, it will be understood that the angular response of the DAS VSP measurements of the seismic / acoustic energy in a wellbore coming from a seismic source on the surface of the wellbore is significantly different from the angular response of the measurements recorded in using a column composed of geophones and / or hydrophones generally approximately equally spaced. For example, hydrophones measure a change in the pressure wave field of detected mechanical seismic waves which are created by a seismic source at a given point relative to a given direction. Hydrophones have an isotropic response to the incident wave field. Geophones generally have a cosine response to the incident P wave field, and the amplitude recorded in the seismic data is significantly decomposed when the incident angle of the wave field is close to 90 ° (cos (90 ° ) = 0). In a system with 2C / 3C configurations available for geophone measurements, the deterioration of the signal amplitude caused by the angular response can be minimized by rotating the axes to transform the seismic data with a component parallel to the angle of incidence.
Figure 4A illustrates an arbitrary angle of incidence; in FIG. 4A, a ray path 402 is emitted by a seismic source 401. An optical fiber 108 is a fiber which is at least partially positioned inside a wellbore (i.e., a borehole 103 illustrated in FIGS. 1A-1C). Θ represents the angle of incidence 404. It must be understood that Θ = 0 for the tangential incidence and θ = ± π / 2 for the perpendicular incidence.
FIG. 4B illustrates the comparison of the response of the amplitude of the P waves of the incident angles of FIG. 4A for the geophone and DAS recording systems. Even if not shown in Figure 4B, the amplitude response of the incident angles s are sin0 and sin20 for the geophone and DAS recording systems, respectively. The vertical axis 408 corresponds to the normalized amplitude of the seismic signal and represents the angular response measured as a function of the angle of incidence. The horizontal axis 406 is shown in radian measurements and represents the measured angle of incidence. A first curve 410 represents geophone measurements, while a second curve 412 represents the DAS VSP measurements corresponding to an angular response relative to the incident angle. Note the abrupt decomposition of the angular response for DAS VSP measurements, particularly at average incident angles. For geophone measurements, the angular response decreases from a normalized amplitude value of about 0.9 to about 0.2 when the angle of incidence is between 0.5 and 1.2 radians. For DAS VSP measurements, the angular response decreases from a normalized amplitude value of approximately 0.75 to approximately 0.05 when the angle of incidence is between 0.5 and 1.2 radians, indicating that geophones generally have an angular response signal proportional to the cosine, while DAS VSP measurements generally have an angular response signal proportional to the squared whatever the column, tubing and cable line layouts ( illustrated in Figures 1A-1C). In the end, the incident angle must be correctly determined for an optimized amplitude recovery from the angular response.
Figure 5 illustrates an example of the ray paths traveling through a flat-layer formation from a finely shifted seismic source to a fiber optic cable deployed in a wellbore. In this example, very close radius paths 402a and 402b travel from a finely shifted seismic source element designed to generate seismic waves and positioned on the surface 112 of the earth through five formation layers 501 to 505 to the optical fiber cable 108 deployed at the bottom of the hole. The rays 402a and 402b can substantially bend when they travel through the different layers 501 to 505, and more particularly, can be spaced apart by Ad when they strike the optical fiber 108. In other words, Ad 506 indicates the distance between two reference points with two defined incident angles Θ 404a and θ '404b from the same radius. In FIG. 5, the instant when the rays 402a and 402b "strike" the optical fiber 108 differs from At 508. Here, it is assumed that the difference in the distance covered Ad 506 and the time At 508 is very small. In this case, from the geometry of Figure 5, we can assume that the two incident angles Θ 404a and θ '404b are identical (θ "θ'). The incident angle Θ can then be determined by the following equation (2):
Has
Ad S (d) ’
COS Θ = (2) in which S (cT) represents the slowness profile along the wellbore as a function of depth d. It must be understood from Equation (2), that to calculate the incident angle or its cosine function, the information processing system 200 must determine two factors, which are the apparent slope of the DAS VSP data acquired ( ^) and the slowness profile (S (d)).
FIG. 6 is a flowchart illustrating a method of real-time or offline processing and recovery of the amplitude of the seismic signals affected the angular response for the DAS VSP data set in accordance with an embodiment of the present disclosure . Before turning to the description of FIG. 6, it is noted that the flow diagram of FIG. 6 shows examples in which the operational steps are carried out in a given order, as indicated by the lines connecting the blocks, but the various steps illustrated in this figure can be carried out in any order, or in any combination or sub-combination. It should be understood that in some embodiments, certain steps described below can be combined into a single step. In some embodiments, one or more steps may be omitted. In some embodiments, one or more additional steps can be performed. As will be understood by those skilled in the art, aspects of this description can be embodied in the form of a process or a computer program product. In certain embodiments, the method described below can be carried out, at least in part, by a software module for controlling the VSP statement 208 illustrated in FIG. 2.
According to an embodiment of the present disclosure, in step 602, the control of the VSP survey 208 can receive an output seismic data stream corresponding to the wells 103 in the DAS system, for example. In various embodiments, the seismic data may include VSP data corresponding to the wellbore, formation or tools within the wellbore. The VSP data may include a plurality of seismic traces, each seismic trace being associated with a depth in the wellbore 103. The VSP data may include data from one or more scans. For example, when VSP data is generated with a vibrator as the seismic source, the VSP data may include a plurality of scans which identify seismic data for the time span corresponding to the length of time the vibration source is engaged. However, when VSP data is generated with an explosive source that emits seismic energy over a shorter period of time, VSP data may include only one scan. In addition, the received VSP data may include data associated with downward propagating direct arrival waves, upward propagated reflected primary waves, downward propagated multiple reflected waves and multiple reflected waves propagating upwards.
Figure 7 illustrates an example of the DAS VSP data set in accordance with given embodiments of this disclosure. The DAS VSP 700 data set includes synthetic data representative of DAS VSP data that can be simulated using a ray tracing method on a multilayer speed model, or other DAS VSP collection techniques within the scope of this disclosure. The DAS VSP data set is illustrated along a time axis 703 and a depth axis 701. As indicated, in a manner that depends at least in part on the characteristics of the environments in the geological formation, such as the formation comprising layers 501 to 505 illustrated in Figure 5, the waves travel at speeds over distances so that relationships can exist between time and space. Consequently, temporal information, as it is associated with the detected energy, can allow an understanding of the spatial relationships of layers, interfaces, structure etc., in a geological formation. The DAS VSP 700 data set illustrated in FIG. 7 comprises one or more seismic traces 702, each seismic trace being associated with a channel, or a depth, in the wellbore 103. As illustrated, the set of DAS VSP 700 data can include a stack of twenty raw scans. Each trace 702 can include an acoustic activity (amplitude) acquired over time in response to the seismic signals propagated through the formation.
When the seismic source is triggered, a pulse wave, shown in Figure 7 by a deep intersection of event 702, travels downward through the various earth formations. At each interface in which the type of rock (layer) changes, part of this wave is reflected towards the surface (hereinafter called upward propagating wave field signals) and another part is transmitted down into the next earth layer (hereinafter called downward propagating wave field signals). In FIG. 7, the reference numbers 704 to 712 indicate the presence of the wave field signals propagating upwards at the level of the corresponding layers of the formation.
As mentioned above, in order to calculate the incident angle, the VSP 208 survey control must determine the slowness profile S ’(d) alongthe wellbore 103.
In various embodiments, the slowness profile could be predetermined by various methods and various sets of sensors which are spaced apart by a predetermined distance.
In one embodiment, the sonic data acquired by a sonic logging tool can be used by a DAS 101 collection system to determine the slowness profile. Sonic logging is a sound sink logging tool that provides a formation transit time interval, which is a measure of the formation's ability to transmit seismic waves. Geologically, this capacity varies with lithology and rock textures, decreasing in particular with an increase in real porosity. In other words, acoustic logging tools provide measurements of the propagation velocities of the acoustic wave through the formation. This means that a sonic log can be used by the DAS 101 collection system to calculate the slowness profile by calculating the travel time of a local acoustic signal generated and received from a logging tool. In various embodiments, the acoustic logging tools can use separate processing streams to obtain the slowness values, and obtain the depth measurements using a natural gamma ray detector or other tools or sensors .
In another embodiment, each waveform has a noise portion (Ni-Nm) which represents the ambient noise signals recorded by each sensor (i.e., geophone sensor) and a signal portion (Si-Sm) which represents the signal sent from the source as it is received by the sensors. The point on the waveform at the start of the signal part is generally called the "first break" or "the first arrival" of the acoustic signal. The delta-t or the slowness of the waveforms can be determined in this embodiment by creating a line which cuts the first break of each waveform and taking the slope of this line. For example, if geophone / DAS measurements of zero offset are available, the DAS 101 collection system can provide the profiles of slowness by differentiating the travel times from the first break, using equation (3) ci below:
S (d) = Δί _ΡΒ / Δά _ΡΒ , (3) in which Δί _ΡΒ represents the time difference between the first break arrivals and Δά _ΡΒ represents the difference in distance between the first break arrivals.
In yet another embodiment, a test fire reading can be used to obtain the values of the slowness profile. The seismic test fire report, also called a seismic reference survey (SRS), is used as the calibration mechanism for the above-mentioned seismic reflection data. In this survey, the seismic velocities are measured in the borehole by recording the time necessary for a seismic signal generated by a surface energy source to reach a geophone anchored at different levels in the boreholes, generally spaced by 'about 100 m or about 300 feet. The vertical seismic profiles are then produced based on the complete seismic trace received at the bottom of the hole at the level of each detector. Automatically, selecting the first break then provides the time-speed-depth data which is further processed to display a relatively noise-free seismic section close to the wellbore.
Referring again to Figure 6, in step 604, checking the VSP reading 208 obtains the values of the slowness profile from the DAS collection system 101 collected using one of the methods described above .
The apparent slope of the acquired DSP VSP data is another factor necessary for controlling the VSP survey 208 to calculate the incident angles. According to an embodiment of the present invention, the apparent slope can be extracted by transforming the data acquired in step 602 into a domain sensitive to the slope / direction. Examples of such domains can include any of the following: tau-p domain (τ - p) (time slowness), curvelet domain, etc.
The transform T of tau-p [f] of a function f is defined by the following equation (4):
T [/] (τ, p) = J f (t - xp, x) dx (4)
By taking the transform tau-p as an example of transformation carried out, a vector of slowness p determines the apparent slope -, c. -to-d. , p = —However, if the control Δα Δα of the VSP statement 208 performs a direct tau-p transform for the entire DAS VSP data set obtained in step 602, the transformed D (τ, ρ) data would be substantially independent of the time t and depth d variables, potentially preventing control of the VSP 208 survey from obtaining good recovery of the angular response. Consequently, according to an embodiment of the present invention, the control of the VSP statement 208 implements the tau-p transform locally (step 606), as shown in FIG. 8.
Figure 8 is a diagram illustrating how the DAS VSP data set is divided into multiple bands, in accordance with an embodiment of this disclosure. As illustrated in FIG. 8, the control of the VSP statement 208 performs the local tau-p transform first by customizing the DAS VSP data set into a plurality of components 802 (hereinafter called band segments). along the depth axis 701. According to an embodiment of the present invention, all the strip segments 802 will probably have a uniform width 806 identified as x in FIG. 8. However, it is obvious that a specialist in the field can use a variable width for each band as long as the width is large enough (generally more than 9 channels) to create a good transform but sufficiently narrow (generally less than 50 channels) to preserve the spatial resolution. The edges of each strip segment 802 are equidistant from a given depth d 804. In addition, it will be understood that the width of each strip segment 802 is substantially narrow compared to the total depth of the well. For example, in a well 4,000 feet deep, the VSP 208 survey control can use band segment width values ranging from about 30 to about 150 feet to perform the local tau-p transform. According to an embodiment of the present invention, the control of the VSP survey 208 determines an apparent local slope for each of the band segments 802 created (step 608) based on the time of arrival of each seismic test at the level of the minus an optical fiber 108.
In this embodiment, the VSP 208 survey control uses the local tau-p transform of the VSP DAS data received in small band segments 802 for different depth values using the following equation (5):
D _d (r, p) = Taup _x (D (t, d)), (5) in which Taup _x (f) is the local tau-p transform with the band segment width 802 x 806, D (t , d) are the DAS VSP data in the space-time domain received in step 602, and D _d (j, p) are the corresponding transformed DAS VSP data in the local tau-p domain at depth d.
Then, in step 610, the control of the VSP reading 208 determines the corrected amplitude corresponding to the angular response (τ, p) for each depth value given using the equation (6):
D _d (r, p) =
DdG.P ') _ Dd (T, p) px cos ² Θ p ² (6) in which p represents the vector of slowness. However, the transform function in equation (6) has a singularity at p = 0. In addition, excessive amplification of the noise level should be avoided. Thus, to facilitate a weaker amplification of the recovered signal for substantially low slowness values, the VSP control 208 can define a minimum slowness value (i.e., p _m i _n ), so that the values the slower ones are pulled by force towards p _m i _n during the realization of the local transform. In this step, the control of the VSP reading 208 uses the values of the slowness profile received in step 604, as mentioned above.
It should be noted that the above examples and equations each assume that waves of only one type are reflected, e.g., P waves. However, the specialist will know that optical fiber 108 can be used to detect other seismic waves including shear waves (S waves) and tubular waves. In the alternative embodiments of the present invention, step 610 may also include determining the corrected amplitude for these types of waves. In this embodiment, controlling the VSP statement 208 transforms the DSP VSP data (in step 606) into a space in which events are separated based on speed. Therefore, equation (6) can be extended to apply to all types of waves:
Dd (Î> P ~) = D _d (_T, p) * A, (7) in which:
For | p | <= 1 / V „ _{+ i;} 4 = ^ = ^ i (8)
For | p | > = 1 / ^ + 0 ^ = - ^ = (9)
N GsCd) /
In other words, equation (7) represents a general solution in which D _d (r, p) represents a transformed data set, A represents a correction factor ^ ΰ ^ ίτ, ρ ') represents the set corrected data transformed. In this embodiment, controlling the VSP statement 208 can use equation (8) to correct the reflections of the P waves corresponding to a predefined range of slope values (ie, | p | <= 1 / VÇ + Ô) and can use equation (9) to correct the reflections of S waves corresponding to a second predefined range of slope values (ie, | p |> = 1 / LÇ, + δ). S waves generally have a sin 2 Θ response to the incident wave field. Furthermore, S _P (d) in equation (8) represents a local slowness profile of P waves, S _s (d) in equation (8) represents a local slowness profile of S waves and δ represents a small shift in the value of p which provides a transition between the correction ranges of the P wave and S wave. Thus, advantageously, the control of the VSP 208 reading performs the local correction of the two wave types at the same time (in the same transformed space) for each band segment 802. For very small values of p, the application of the correction to equations (8) and (9) directly will result in a singularity (by dividing by zero). To alleviate this problem, a threshold level is defined for the values of p, below which a small value is replaced by p. For example, a threshold value of could be set to 10 ' ⁶ so that for all values of p less than p _min , the value of 10' ⁶ will be replaced by p. It will be understood that in various embodiments, the control of the VSP statement 208 can modify the operating range of A in order to correct the tubular waves also, for which the correction of the amplitude and the uniqueness. In one embodiment, the control of the VSP statement 208 can achieve a harmonious transition of the ranges of the values of A rather than a transition by step.
Then, in step 612, the control of the VSP statement 208 applies an inverted Tau-p transformation to project the data set of the corrected tau-p domain back into the space-time domain.
In order to better illustrate the various embodiments and to explain the principles and advantages in accordance with the present disclosure, the processing of the synthetic records with a divergence t ² and an applied angular response is compared with the processing of the records with the corrected angular response. Beginning with Figure 9, an example of a DAS VSP data set acquired using a seismic source located approximately 200 feet from the wellhead is illustrated. In this case, the optical fiber cable, such as the optical fiber cable 108 extends from the depth of about 0 to about 500 feet. The underground formation is considered to be homogeneous, in which the speed of sound and about 550 feet / sec. Seismic waves generally propagate in three dimensions, and the surface area on the spherical wave that extends increases in proportion to the square of the radius. Thus, in this case the function t ² was used as a scaling factor. Figure 9 shows the synthetic DSP VSP dataset sample with 1 foot spatial sampling and 1 millisecond temporal sampling of the downward traveling wave field to produce a 902 seismic trace and selections of corresponding "first breaks" on the refraction events 904 are superimposed. Since the speed / slowness for the substantially homogeneous medium is known and the synthetic data are substantially free of noise, only the local slope is calculated and its threshold Pmin is correctly defined. In this example, the threshold is defined as being slightly greater than zero, such as 10 ^_6 s / m.
According to an embodiment of the present invention, the correction of the amplitude relative to the incident angles for each channel is obtained by carrying out a local tau-p transform as presented above in relation to FIGS. 6 and 8. FIGS. 10A-10D illustrate the approach for identifying the incident angles in the domain τ - p, and the incident angles calculated with respect to the depth of the channel using a synthetic example DAS VSP, according to the modes of carrying out the present invention; starting with Figure 10A, four examples of events in a synthetic DSP VSP dataset are illustrated. These events include a downward propagating P wave 1000, a downward propagating S wave 1002, an upward propagating P wave 1004 and an upward propagating S wave 1006.
Figure 10B illustrates the same DAS VSP data set defined only in the tau-p domain. In this figure, events 1010, 1012, 1014,1016 correspond to events 1006, 1004, 1000, 1002 in Figure 10A, respectively. In addition, Figure 10B contains three dotted lines to help illustrate the four p-areas corresponding to the P waves and S waves traveling down and up in the corresponding striped segment, as described above. The downwardly propagating P waves are located between the dotted lines at p = Q and p = 1.5. The upwardly propagating P waves are located between the dotted line at / 2 = -1.5 and p = Q. The downward propagating S waves are located to the right of / »= 1.5. The upwardly propagating S waves are located to the left of / »= - 1.5.
FIG. 10C illustrates a modified tau-p transform (Eq. 5) carried out on a single P 902 wave event on the DAS VSP synthetic data set illustrated in FIG. 9. A series of tau-p transforms is calculated, one for each strip as described above. Each of these tau-p transforms is summarized through the tau domain which creates a unique trace for each of them in Figure 10, corresponding to the central depth of each strip. The resulting transformed P wave event is illustrated as 1018 in Figure 10C. The corresponding p-value for each depth provides an estimate of the local slope of the event at each depth. Figure 10D illustrates the relationship between the theoretical values and the local slope values (/>) from Figure 10C converted to incident angles in accordance with an embodiment of the present invention. In this case, a seismic source is also located about 200 feet from the well head. A first curve 1020 illustrates the experimental values reported as incident angle versus depth. A second trace 1022 illustrates theoretical values also reported in the form of an incident angle versus depth. A substantially complete overlap between the theoretical and experimental values indicates the validity of the calculation method described above in accordance with an embodiment of the present invention.
FIG. 11 illustrates the comparison of the seismic signal traces before and after the compensation of the angular response in accordance with the embodiments of the present invention, illustrated along an axis of the RMS amplitude and an axis of depth. A first trace 1102 in FIG. 11 illustrates the RMS amplitude of the seismic signal before applying the method of compensation for the angular response described above versus the depth. A second trace 1104 illustrates the amplitude recovered after application of the angular response compensation method in accordance with reported embodiments of the present invention versus depth. A third trace 1006 illustrates theoretical values corresponding to the omnidirectional angular response. Figure 11 clearly illustrates a substantially complete recovery of the amplitude values at depths ranging from about 0 to about 500 feet. Furthermore, such recovered amplitude values correspond substantially to the theoretical model as well. It should be noted that compared to the methods described above, a trace at a depth of 0 feet is extrapolated using the data at a shallow depth other than zero since this trace disappears after using the response. angular (because cos 90 = 0).
Advantageously, this approach described above does not depend on the geology of the formation. In other words, the angular response can be compensated by checking the VSP reading 208 for all the rays detected, regardless of how these rays have traveled before hitting the fiber optic cable 108. In addition or otherwise, this approach can simply be applied to substantially any amplitude values, even if the angular response values are superimposed on other amplitude factors, such as, without limitation, the spherical divergence, l , diffusion, etc. Due to the fact that the right portion of the signal amplitude will be isolated at its corresponding angle after application of the direction-specific transforms described above, this approach is applicable even if events (i.e., direct incoming waves propagating downward, reflected primary waves propagating upward, multiple reflected waves propagating downward and multiple reflected waves propagating upward) cross. As previously described, the angular response compensation method requires the determination of the speed / slowness profile only in the vicinity of the wellbore, and the measurements of the anisotropy of the low seismic speed are assumed in each layer of training near the wellbore. In the embodiments described above, the tau-p transform is used to calculate the local apparent slopes. The tau-p transform changes the seismic data from the space-time domain to the domain of the radius parameter of the crossing time. However, in alternative embodiments, other transforms can be used to obtain an upward and downward propagating transformed wavefield, such as, without limitation, a sparse tau-p transform (variants d '' a tau-p transform with a constraint of norm L1), a Curval transform and, a direct derivative, etc.
Therefore, as described above, the embodiments disclosed here can be implemented in a number of ways. Generally, in one aspect, the disclosed embodiments are directed to a system for processing DAS VSP readings in real time. The system includes, among other things, a distributed acoustic detection data collection (DAS) system coupled to at least one optical fiber at least partially positioned inside a wellbore and designed to activate an energy source. or to listen to a source of seismic energy for one or more times. The system also includes an information processing system coupled in communication with the DAS data collection system. The information processing system includes a processor and a memory coupled to the processor. The memory device contains a set of instructions which, when executed by the processor, allows the processor to receive a set of seismic data from the DAS data collection system. The seismic data set includes a plurality of seismic data records which are each associated with different activation of the source by the DAS data collection system to produce a seismic signal. The instruction set, when executed by the processor, also allows the processor to i) receive the slowness profile as a function of the depth measured inside the wellbore from the DAS data collection system or a VSP processing system; ii) transform the seismic dataset into the dataset of the domain of the radius and interception time parameter; iii) determine the local apparent slope for each seismic test in the set of seismic data received; iv) perform the amplitude correction for the seismic signals received using the slowness profile and the local apparent slope determined in the data set of the radius and interception time parameter; and v) transform the data set of the domain of the radius and time crossing parameter into a space-time domain.
In one or more embodiments, the distributed optical fiber detection system may also include any of the following features, individually or any of two or more of these features in combination: a) the instruction set which allows the processor to transform the seismic dataset into the dataset of the radius and interception time parameter also allows the processor to transform the seismic dataset into the dataset of the tau-p domain ; (b) the local apparent slope is determined based on the time of arrival of each seismic signal at the level of at least one optical fiber; (c) the instruction set which allows the processor to transform the seismic data set into the interception radius and time parameter data set also allows the processor to divide each seismic data record into the set data in multiple components, wherein each of the components is associated with a given depth within the wellbore and wherein each of the components has a uniform width with respect to the given depth; (d) the seismic signal comprises a seismic P wave and a combined seismic S wave; (e) the instruction set which allows the processor to transform the seismic data set into the interception time and radius parameter data set also allows the processor to separate the seismic signals corresponding to the corresponding P waves from the signals seismic corresponding to S waves based on the measured speed of seismic signals; (f) the instruction set which allows the processor to carry out the correction of the incident angle also allows the processor to carry out the correction of the incident angle separately for the seismic signals corresponding to the P waves and for the seismic signals corresponding to the S waves; and (g) the set of instructions which allows the processor to transform the seismic data set into the data set of the radius and interception time parameter also allows the processor to carry out one of a transform of tau-p slope stacks and a sparse tau-p transform.
Generally, in yet another aspect, the disclosed embodiments are akin to a method of processing DAS VSP readings to achieve amplitude correction in real time. The method includes, among other steps, the steps of repeatedly activating or listening to a seismic energy source by a distributed acoustic detection data collection (DAS) system coupled to at least one optical fiber at the less partially positioned inside a wellbore and sending a seismic data set acquired from the DAS data collection system to an information processing system coupled in communication to the data collection system DAS data. The seismic data set includes a plurality of seismic data records each of which is associated with different activation of the source by the DAS data collection system to produce a seismic signal. The method also includes the following steps: i) sending the slowness profd as a function of the depth measured inside the wellbore from the DAS data collection system or from a processing system VSP to an information processing system; ii) transform, by the information processing system, the seismic data set into the data set of the radius parameter domain and time crossing; iii) determine, by the information processing system, the local apparent slope for each seismic test in the set of seismic data received; iv) carry out, by the information processing system, the amplitude correction for the seismic signals received using the slowness profd and the local apparent slope determined in the data set of the radius parameter domain and temporal crossing; and v) transform, by the information processing system, the data set of the domain of the radius and time crossing parameter into a space-time domain.
In one or more embodiments, the method for processing DAS VSP readings to perform amplitude correction processing in real time or off-line may also include one or more of the following characteristics individually or any one of two or more of these characteristics in combination: (a) the DAS data collection system comprising a data interrogation device coupled in communication to one end of the at least one optical fiber and positioned at a surface of the earth; (b) the step of transforming the seismic data set into a data set of the radius and interception time parameter also comprising the step of transforming the seismic data set into the data set of the tau domain -p; (c) the step of determining the local apparent slope based on the time of arrival of each seismic signal at the level of at least one optical fiber; and (d) the step of transforming the seismic data set into the interception time and radius parameter data set also comprising dividing each seismic data record in the data set into multiples components, in which each of the components is associated with a given depth inside the wellbore and in which each of the components has a uniform width with respect to the given depth.
While given aspects, implementations and applications of this disclosure have been illustrated and described, it should be understood that this disclosure is not limited to the precise construction and the compositions disclosed herein and that various modifications, changes and variations may be evident from the foregoing descriptions without departing from the spirit and scope of the disclosed embodiments as defined in the appended claims.

权利要求:
Claims (10)
[1" id="c-fr-0001]
What is claimed:
1. System, comprising:
a distributed acoustic detection (DAS) data collection system coupled to at least one optical fiber at least partially positioned inside a wellbore and designed to activate a source of seismic energy or to listen to a source of seismic energy one or more times; and an information processing system coupled in communication with the DAS data collection system, the information processing system comprising a processor and a memory device coupled to the processor, the memory device containing an instruction set which, when executed by the processor, allows the processor to perform the following steps:
receiving a seismic data set from the DAS data collection system recorded in a space-time domain, the seismic data set comprising a plurality of seismic data records which are each associated with different activation of the source by the DAS data collection system for producing a seismic signal;
receive a slow profile as a function of the depth measured inside the wellbore from the DAS data collection system or from the VSP processing system;
transform the seismic dataset into the dataset of the domain of the radius and interception time parameter;
determining the local apparent slope for each seismic signal in the received seismic data set;
perform the amplitude correction for the seismic signals received using the slowness profile and the local apparent slope determined in the dataset of the domain of the radius and interception time parameter; and transform the dataset of the domain of the radius and interception time corrected parameter into space-time domain.
[2" id="c-fr-0002]
2. The system of claim 1, wherein the instruction set which allows the processor to transform the seismic dataset into the dataset of the domain of the radius and interception time parameter also allows the processor to transforming the seismic data set into the tau-p domain data set and / or the instruction set also allows the processor to split each seismic data record into multiple components, in which each of the components is associated with a given depth inside the wellbore and / or in which the local apparent slope is determined based on the time of arrival of each seismic signal at the level of the at least one optical fiber.
[3" id="c-fr-0003]
The system of claim 1, wherein the seismic signal comprises a seismic P-wave, a seismic S-wave, or a combination of the two, and wherein the instruction set which allows the processor to transform the seismic data set into the dataset of the domain of the radius and interception time parameter also allows the processor to separate the seismic signals corresponding to the P waves from the seismic signals corresponding to the S waves based on the measured speed of the seismic signals and / or in which the instruction set which allows the processor to carry out the amplitude correction also allows the processor to carry out the amplitude correction separately for the seismic signals corresponding to the P waves and for the seismic signals corresponding to the S waves and / or in which the value of the slowness profile is associated with the S waves or the value of the slowness profile is associated with the P waves and in leq or the slowness profile is obtained using a zero offset, a VSP test fire report or a sonic log.
[4" id="c-fr-0004]
4. The system of claim 1, wherein the set of instructions which allows the processor to transform the seismic dataset into the dataset of the domain of the radius and interception time parameter also allows the processor to performing one of a tau-p slope stack transform and a sparse tau-p transform and in which the DAS data collection system includes a data interrogation device coupled in communication at one end of the at least one optical fiber and positioned at the level of the earth's surface.
[5" id="c-fr-0005]
5. Process for processing DAS VSP readings to carry out the amplitude correction in real time or offline, the process comprising:
activation of a seismic energy source or listening to a seismic energy source by a distributed acoustic detection data collection system (DAS) coupled to at least one optical fiber at least partially positioned at l inside a wellbore;
sending an acquired seismic data set originating from the DAS data collection system to an information processing system coupled in communication to the DAS data collection system, the seismic data set comprising a plurality of records seismic data which are each associated with different activation of the source by the DAS data collection system to produce a seismic signal;
sending a slowness profile as a function of the depth measured inside the wellbore from the DAS data collection system or from the VSP processing system to an information processing system;
the transformation, by the information processing system, of the seismic data set into the data set of the domain of the radius and interception time parameter;
the determination, by the information processing system, of the local apparent slope for each seismic signal in the received seismic data set;
the implementation, by the information processing system, of the amplitude correction for the seismic signals received using the slowness profile and the local apparent slope determined in the dataset of the domain of the parameter of radius and interception time; and the transformation, by the information processing system, of the domain data set of the radius and interception time corrected parameter into the space-time domain.
[6" id="c-fr-0006]
6. The method as claimed in claim 5, in which the DAS data collection system comprises a data interrogation device coupled in communication to one end of the at least one optical fiber and positioned at the level of the earth's surface and / or in which the transformation of the seismic data set into the data set of the domain of the radius and interception time parameter comprises the transformation of the seismic data set into the data set of the tau domain -p.
[7" id="c-fr-0007]
7. Method according to claim 6, in which the local apparent slope is determined based on the arrival time of each seismic signal at the level of the at least one optical fiber or in which the transformation of the data set seismic in the dataset of the domain of the radius and interception time parameter includes the division of each record of seismic data in the dataset into multiple components, in which each of the components is associated with a given depth inside the wellbore.
[8" id="c-fr-0008]
8. The method as claimed in claim 5, in which the seismic signal comprises a seismic P wave and a seismic S wave combined and in which the transformation of the seismic data set into the data set of the domain of the radius parameter and of interception time comprises the separation of the seismic signals corresponding to the P waves from the seismic signals corresponding to the S waves based on the measured speed of the seismic signals and / or in which the carrying out of the amplitude correction comprises the carrying out, separately, of amplitude correction for seismic signals corresponding to P waves and for seismic signals corresponding to S waves
[9" id="c-fr-0009]
9. An information processing system coupled in communication to a distributed acoustic detection data collection system (DAS), the information processing system comprising a processor and a memory device coupled to the processor, the memory device containing an instruction set which, when executed by the processor, allows the processor to:
receiving an acquired seismic data set from the distributed DAS data collection system, the seismic data set comprising a plurality of seismic data records which are each associated with a different activation time from the source or with a time different listening to the source by the DAS data collection system to produce a seismic signal;
receive a slow profile as a function of the depth measured inside the wellbore from the DAS data collection system or from the VSP processing system;
transform the seismic dataset into the dataset of the domain of the radius and interception time parameter;
determining the local apparent slope for each seismic signal in the received seismic data set;
perform the amplitude correction for the seismic signals received using the slowness profile and the local apparent slope determined in the dataset of the domain of the radius and interception time parameter; and transform the dataset from the domain of the radius and interception time corrected parameter into spatiotemporal domain. "
[10" id="c-fr-0010]
10. The information processing system as claimed in claim 9, in which the set of instructions which allows the processor to transform the seismic data set into the data set of the domain of the radius and interception time parameter. also allows the processor to transform the seismic data set into the set of 5 data from the tau-p domain.

类似技术:

---

公开号 | 公开日 | 专利标题

---

FR3068479A1|2019-01-04|ANGULAR RESPONSE COMPENSATION FOR VSP DSP

---

US10444391B2|2019-10-15|Noise removal for distributed acoustic sensing data

---

Sladen et al.2019|Distributed sensing of earthquakes and ocean-solid Earth interactions on seafloor telecom cables

---

Zhan2020|Distributed acoustic sensing turns fiber‐optic cables into sensitive seismic antennas

---

Hornman2017|Field trial of seismic recording using distributed acoustic sensing with broadside sensitive fibre‐optic cables

---

Parker et al.2014|Distributed Acoustic Sensing–a new tool for seismic applications

---

US10401519B2|2019-09-03|Noise removal for distributed acoustic sensing data

---

Spica et al.2020|Urban seismic site characterization by fiber‐optic seismology

---

Fernández-Ruiz et al.2020|Distributed acoustic sensing for seismic activity monitoring

---

EP2253970B1|2014-01-22|Method for imaging a target area of the subsoil using walkaway data

---

US20200271811A1|2020-08-27|Real-time processing and control of das vsp surveys

---

Lellouch et al.2019|Seismic velocity estimation using passive downhole distributed acoustic sensing records: Examples from the San Andreas fault observatory at depth

---

Correa et al.2019|3D vertical seismic profile acquired with distributed acoustic sensing on tubing installation: A case study from the CO2CRC Otway Project

---

Barberan et al.2012|Multi-offset seismic acquisition using optical fiber behind tubing

---

Papp et al.2017|A study of the geophysical response of distributed fibre optic acoustic sensors through laboratory‐scale experiments

---

Castongia et al.2017|An experimental investigation of distributed acoustic sensing | on lake ice

---

FR3049355A1|2017-09-29|

---

FR3077142A1|2019-07-26|OPTIMIZING A REFERENCE LENGTH FOR SIGNAL PRESERVATION AND PROCESSING A REFERENCE LENGTH FOR DISTRIBUTED VIBRATION DETECTION PURPOSES

---

US10281606B2|2019-05-07|Creating 3C distributed acoustic sensing data

---

Ellmauthaler et al.2020|Distributed acoustic sensing of subsea wells

---

Perton et al.2020|Shear wave structure of a transect of the Los Angeles basin from multimode surface waves and H/V spectral ratio analysis

---

Shragge et al.2021|Low-frequency ambient distributed acoustic sensing |: case study from Perth, Australia

---

Pevzner et al.2018|Repeat logging using distributed acoustic sensors and earthquakes

---

Correa et al.2017|DAS versus geophones: A quantitative comparison of a VSP survey at a dedicated field laboratory

---

Farhadiroushan et al.2019|Advanced geophysical measurement methods using engineered fiber optic acoustic sensor

同族专利:

---

公开号 | 公开日

---

US20210199832A1|2021-07-01|

---

GB2577189A|2020-03-18|

---

GB201916559D0|2020-01-01|

---

WO2019005050A1|2019-01-03|

---

CA3064870A1|2019-01-03|

---

CA3064870C|2021-12-28|

---

MX2019014296A|2020-01-27|

---

NO20191402A1|2019-11-25|

---

US11079511B2|2021-08-03|

---

AU2017420719A1|2019-11-28|

引用文献:

---

公开号 | 申请日 | 公开日 | 申请人 | 专利标题

---

---

US4779238A|1987-04-13|1988-10-18|Conoco Inc.|Method for fast slant stack of seismic data|

---

US6314056B1|1998-01-23|2001-11-06|Petroleum Geo-Services|Fiber optic sensor system and method|

---

US6724319B1|1999-10-29|2004-04-20|Litton Systems, Inc.|Acoustic sensing system for downhole seismic applications utilizing an array of fiber optic sensors|

---

US6691039B1|2002-08-30|2004-02-10|John M. Robinson|Removal of noise from seismic data using improved radon transformations|

---

US7065004B2|2004-04-22|2006-06-20|Pgs Americas, Inc.|Horizon-based residual depth migration velocity analysis|

---

GB2436872A|2006-04-06|2007-10-10|Qinetiq Ltd|Fibre-optic sensor package|

---

US20110088462A1|2009-10-21|2011-04-21|Halliburton Energy Services, Inc.|Downhole monitoring with distributed acoustic/vibration, strain and/or density sensing|

---

GB201104423D0|2011-03-16|2011-04-27|Qinetiq Ltd|Subsurface monitoring using distributed accoustic sensors|

---

US9075155B2|2011-04-08|2015-07-07|Halliburton Energy Services, Inc.|Optical fiber based downhole seismic sensor systems and methods|

---

US8687470B2|2011-10-24|2014-04-01|Lsi Corporation|Optical disk playback device with three-dimensional playback functionality|

---

US9176249B2|2011-12-21|2015-11-03|Cggveritas Services Sa|Device and method for processing variable depth streamer data|

---

US9103941B2|2011-12-21|2015-08-11|Cggveritas Services Sa|Device and method for deghosting variable depth streamer data|

---

US9122033B2|2012-10-15|2015-09-01|Halliburton Energy Services, Inc.|Method to install sensing cables in monitoring wells|

---

US20140150523A1|2012-12-04|2014-06-05|Halliburton Energy Services, Inc.|Calibration of a well acoustic sensing system|

---

US20140204712A1|2013-01-24|2014-07-24|Halliburton Energy Services, Inc.|Downhole optical acoustic transducers|

---

US10247840B2|2013-01-24|2019-04-02|Halliburton Energy Services, Inc.|Optical well logging|

---

US20140219056A1|2013-02-04|2014-08-07|Halliburton Energy Services, Inc. |Fiberoptic systems and methods for acoustic telemetry|

---

AU2014260145C1|2013-04-29|2018-07-26|Westerngeco Seismic Holdings Limited|Deghosting with adaptive operators|

---

WO2014201313A1|2013-06-13|2014-12-18|Schlumberger Canada Limited|Fiber optic distributed vibration sensing with directional sensitivity|

---

US10345470B2|2014-01-13|2019-07-09|Cgg Services Sas|Device and method for deghosting seismic data using sparse tau-p inversion|

---

EP3143249A4|2014-07-17|2018-01-10|Halliburton Energy Services, Inc.|Noise removal for distributed acoustic sensing data|

---

WO2016039928A1|2014-09-12|2016-03-17|Halliburton Energy Services, Inc.|Noise removal for distributed acoustic sensing data|

---

WO2016159939A1|2015-03-27|2016-10-06|Halliburton Energy Services, Inc.|Coherent noise attenuation using statistical methods|

---

US20190086571A1|2016-05-25|2019-03-21|Halliburton Energy Services, Inc.|An improved stoneley wave slowness and dispersion curve logging method|

---

US10310133B2|2016-10-04|2019-06-04|Fairfield Geotechnologies|Calibration of geophone and hydrophone pairs|

---

US10754051B2|2017-01-13|2020-08-25|Magseis Ff Llc|3D tau-P coherency filtering|

---

US11079511B2|2017-06-28|2021-08-03|Halliburton Energy Services, Inc.|Angular response compensation for DAS VSP|US11199084B2|2016-04-07|2021-12-14|Bp Exploration Operating Company Limited|Detecting downhole events using acoustic frequency domain features|

---

US20200182047A1|2016-04-07|2020-06-11|Bp Exploration Operating Company Limited|Detecting Downhole Sand Ingress Locations|

---

EA038373B1|2017-03-31|2021-08-17|Бп Эксплорейшн Оперейтинг Компани Лимитед|Well and overburden monitoring using distributed acoustic sensors|

---

US11079511B2|2017-06-28|2021-08-03|Halliburton Energy Services, Inc.|Angular response compensation for DAS VSP|

---

EP3673148B1|2017-08-23|2021-10-06|BP Exploration Operating Company Limited|Detecting downhole sand ingress locations|

---

WO2021073740A1|2019-10-17|2021-04-22|Lytt Limited|Inflow detection using dts features|

---

WO2021093974A1|2019-11-15|2021-05-20|Lytt Limited|Systems and methods for draw down improvements across wellbores|

法律状态:
2019-05-23| PLFP| Fee payment|Year of fee payment: 2 |

---

2020-10-02| PLSC| Publication of the preliminary search report|Effective date: 20201002 |

---

2021-02-12| ST| Notification of lapse|Effective date: 20210105 |

优先权:

---

申请号 | 申请日 | 专利标题

---

IBWOUS2017039823|2017-06-28|

---

PCT/US2017/039823|WO2019005050A1|2017-06-28|2017-06-28|Angular response compensation for das vsp|

---