Full automation of high-resolution interval velocity estimation for check-shot and other vertical seismic profile-type dataset

Abstract

To provide full automation of high-resolution interval velocity estimation for check-shot and other vertical seismic profile-type datasets.SOLUTION: A method includes the steps of: disposing sensors within a borehole; disposing seismic sources on a surface away from a wellhead of the borehole at a field location; propagating seismic waves using the seismic sources; obtaining particle velocity data from geological stratum in the field location; obtaining strain data from the geological stratum in the field location; performing a peak-to-peak amplitude analysis for the particle velocity data for a target phase; performing a peak-to-peak amplitude analysis for the strain data for the target phase; and estimating a velocity of waves in the geological stratum based upon the peak-to-peak amplitude analysis for the particle velocity data for the target phase and the peak-to-peak amplitude analysis for the strain data for the target phase.SELECTED DRAWING: None

Description

[Technical Field]

[0001] [CROSS-REFERENCE TO RELATED APPLICATIONS] This application is a continuation-in-part of U.S. Non-provisional Application No. 17 / 165,239, filed February 2, 2021, which issued as U.S. Patent No. 11,921,247 on March 5, 2024, which is incorporated by reference in its entirety for all purposes.

[0002] [Technical field] Aspects of the present disclosure relate to the analysis of seismic data, and more particularly to an automated method for obtaining velocity estimates without requiring time selection of an analysis interval. [Background technology]

[0003] Borehole seismic projects attempt to estimate P- and S-wave velocities along the borehole by measuring the velocity of seismic waves recorded in the borehole. Because borehole types and geometries can vary, there are many different types of overall configurations that can exist. Figures 1A-1M present various types of applications in which borehole seismic profiles can be used. In Figure 1A, for example, a checkshot vertical seismic profile (VSP) and a zero-offset VSP (Figure 1E) are the most basic configurations to consider, as they provide P- and S-wave velocities along the borehole. As shown in Figure 1A, a derrick 101 is positioned to prepare a well 100. A seismic source 102 is configured to transmit a sonic pulse 104 into the formation. Figures 1B-1M provide various types of embodiments for providing seismic pulses in different configurations. As provided in Figure 1B, multiple patterns from multiple seismic sources are shown. In Figure 1C, multiple seismic sources 112 are provided in the well. In FIG. 1H, waveform patterns 110 are generated from different seismic sources. In different embodiments, an artificial seismic source is placed near the borehole wellhead, and direct P-wave (and possibly both P-wave and S-wave) arrivals are recorded using downhole sensors. Variations in P-wave and S-wave velocity can be inferred in terms of propagation direction (anisotropy) by using several different configurations, including offset VSP (FIG. 1G), normal incidence VSP, walk-above VSP (FIG. 1D), walk-around VSP (FIG. 1I), and 3D VSP (FIG. 1M). These explorations provide important information for seismic imaging and reservoir characterization. In addition to these figures, as explained above, other geometries and variations are shown as examples of different configurations and methods that may be used.

[0004] Traditionally, three-component (3C) sensors have been used in the borehole seismic industry. More recently, fiber-based systems such as heterodyne distributed acoustic sensing (hDVS) systems or distributed acoustic sensing (DAS) systems have seen increased popularity due to their low implementation costs and associated short acquisition times. However, these systems are single-component (1C) acquisition systems.

[0005] Traditional approaches to data acquired from the various systems and geometries described above rely on analysts to "time-select" the various data sets acquired. Such selection involves many factors and is a very difficult task. This task slows down analysis and, consequently, activity in the field.

[0006] It is necessary to provide a method that does not involve redundant analysis, such as time interval selection, as is currently done in conventional analysis.

[0007] Furthermore, there is a need to provide a method that does not address the drawbacks discussed above, namely, wasting operator and analyst time.

[0008] Furthermore, there is a need to reduce the economic costs associated with field and analyst time associated with time selection intervals. Summary of the Invention

[0009] So that the above-recited features of the present disclosure can be understood in detail, a more particular description of the present disclosure will be understood by reference to the embodiments briefly summarized below, some of which are illustrated in the drawings. It should be noted that the drawings illustrate only typical embodiments of the present disclosure, and therefore, these typical embodiments should not be considered as limiting the scope of the present disclosure, and other equally effective embodiments may be recognized without being specifically recited. Therefore, the following summary provides only some aspects of the specification and should not be used to limit the described embodiments to a single concept.

[0010] In one exemplary embodiment, a method is disclosed. The method may include testing and acquiring particle velocity data from at least one geological formation at a field location. The method may further include acquiring strain data from the at least one geological formation at the field location. The method may further include performing a peak-to-peak amplitude analysis on the particle velocity data of a target phase. The method may further include performing a peak-to-peak amplitude analysis on the strain data of the target phase. The method may further include estimating a wave velocity in the at least one geological formation based on the peak-to-peak amplitude analysis on the particle velocity data of the target phase and the peak-to-peak amplitude analysis on the strain data of the target phase.

[0011] In another exemplary embodiment, a method is disclosed. The method may include disposing one or more sensors in a borehole, disposing one or more seismic sources outside the borehole at or near the borehole head at a field location, and propagating seismic waves using the one or more seismic sources. The method may further include acquiring particle velocity data from at least one geological formation at the field location, acquiring strain data from at least one geological formation at the field location, performing a peak-to-peak amplitude analysis on the particle velocity data of a target phase, performing a peak-to-peak amplitude analysis on the strain data of the target phase, and estimating wave velocity in the at least one geological formation based on the peak-to-peak amplitude analysis on the particle velocity data of the target phase and the peak-to-peak amplitude analysis on the strain data of the target phase.

[0012] In another exemplary embodiment, a method is disclosed. The method may include disposing one or more sensors in a borehole, disposing one or more seismic sources outside the borehole at a field location away from the borehole wellhead, and propagating seismic waves using the one or more seismic sources. The method may further include acquiring particle velocity data from at least one geological formation at the field location, acquiring strain data from at least one geological formation at the field location, performing a peak-to-peak amplitude analysis on the particle velocity data of a target phase, performing a peak-to-peak amplitude analysis on the strain data of the target phase, and estimating wave velocity in the at least one geological formation based on the peak-to-peak amplitude analysis on the particle velocity data of the target phase and the peak-to-peak amplitude analysis on the strain data of the target phase.

[0013] So that the above-recited features of the present disclosure may be understood in detail, a more particular description of the present disclosure will be understood by reference to the embodiments briefly summarized above, some of which are illustrated in the drawings. It should be noted that the drawings illustrate only typical embodiments of the present disclosure, and therefore, those typical embodiments should not be considered as limiting the scope of the present disclosure, as other equally effective embodiments may be recognized. [Brief explanation of the drawings]

[0014] [Figure 1A] This is a side cross section of a check shot vertical seismic profile being conducted at the well site.

[0015] [Figure 1B] This is a side section of a walkaway vertical seismic profile being conducted at the well site.

[0016] [Figure 1C] This is a side section of a single seismic test being conducted at the well site.

[0017] [Figure 1D] This is a side section of a walk-above vertical seismic profile being conducted at the well site.

[0018] [Figure 1E] 1 is a side section of a zero-offset vertical seismic profile being conducted at the well site.

[0019] [Figure 1F] This is a side section of a single-well seismic profile being conducted at the well site.

[0020] [Figure 1G] This is a side section of an offset vertical seismic profile being conducted at the well site.

[0021] [Figure 1H] 1 is a side cross section of a vertical seismic profile versus offset test being conducted at the well site.

[0022] [Figure 1I] This is a side section of a walk-around vertical seismic profile being conducted at the well site.

[0023] [Figure 1J] This is a cross-section of a seismic test while drilling being conducted at the well site.

[0024] [Figure 1K] This is a cross-section of a cross-well seismic test being conducted at the well site.

[0025] [Figure 1L] This is a side cross section of a salt proximity test being conducted at a well site.

[0026] [Figure 1M] This is a cross-section of a 3D vertical seismic profile test being conducted at the well site.

[0027] [Figure 2]A method for fully automating high-resolution interval velocity estimation for check-shot and other vertical seismic profile type datasets.

[0028] [Figure 3A] 1 is an exemplary embodiment of strain checkshot vertical seismic profile data.

[0029] [Figure 3B] 1 is an exemplary embodiment of particle velocity check-shot vertical seismic profile data.

[0030] [Figure 4] 3 is a graph showing a comparison of conventional time-selected speeds with the fully automatic speed calculation described in FIG. 2.

[0031] [Figure 5] 2 is a computer system for use in implementing the method and control system for the operation of FIG. 1;

[0032] [Figure 6] FIG. 1 is a side view of an active wireline operation in which seismic analysis can be performed.

[0033] [Figure 7] A method for obtaining check shot or zero offset vertical seismic profiles.

[0034] [Figure 8] A method for obtaining walk-away, walk-above, or 3D vertical seismic profiles.

[0035] [Figure 9] A method for obtaining cross-well vertical seismic profiles. DETAILED DESCRIPTION OF THE INVENTION

[0036] For ease of understanding, wherever possible, like reference numerals have been used to designate like elements common to the drawings ("FIGS") It is contemplated that elements disclosed in one embodiment may be beneficially utilized on other embodiments without being specifically recited.

[0037] Reference will be made below to embodiments of the present disclosure. However, it should be understood that the present disclosure is not limited to the specifically described embodiments. Instead, any combination of the following features and elements, whether associated with different embodiments or not, is contemplated for implementing and practicing the present disclosure. Furthermore, while embodiments of the present disclosure may achieve advantages over other possible solutions and / or over the prior art, whether or not a particular advantage is achieved by a given embodiment does not limit the present disclosure. Accordingly, the following aspects, features, embodiments, and advantages are merely exemplary and should not be considered claim elements or limitations unless expressly recited in the claims. Similarly, references to "the present disclosure" should not be construed as generic to the inventive subject matter disclosed herein, and should not be considered claim elements or limitations unless expressly recited in the claims.

[0038] Terms such as "first," "second," "third," and the like may be used herein to describe various elements, components, regions, layers, and / or sections; however, these elements, components, regions, layers, and / or sections are not limited by these terms. These terms may be used only to distinguish one element, component, region, layer, or section from another region, layer, or section. When used herein, terms such as "first," "second," and other numerical terms do not imply a sequence or order unless clearly indicated by context. Thus, a first element, component, region, layer, or section described herein may be referred to as a second element, component, region, layer, or section without departing from the teachings of the exemplary embodiments.

[0039] When an element or layer is referred to as "being," "engaged," "connected," or "coupled" to another element or layer, the element or layer may be directly situated, engaged, connected, or coupled to the other element or layer, or there may be intervening elements or layers. In contrast, when an element is referred to as "directly situated," "directly engaged," "directly connected," or "directly coupled" to another element or layer, there may be no intervening elements or layers. Other words used to describe relationships between elements should be interpreted similarly. As used herein, the term "and / or" includes any and all combinations of one or more of the associated listed terms.

[0040] Some embodiments will now be described with reference to the drawings. Like elements in various figures will be referenced with like numerals for consistency. In the following description, numerous details are set forth to provide an understanding of various embodiments and / or features. However, one of ordinary skill in the art will understand that some embodiments may be practiced without many of these details and that many variations or modifications from the described embodiments are possible. As used herein, the terms "above" and "below," "on" and "below," "upper" and "lower," "upward" and "downward," and other similar terms indicating relative positions above or below a given point, are used in this description to more clearly describe particular embodiments.

[0041] Aspects of the present disclosure also provide methods that may be implemented to achieve the stated objectives, including controlling the components described herein. In some embodiments, the described methods may be implemented by circuitry and / or a computer configured to perform such tasks.

[0042] With reference to Figure 6, wireline operations are performed after the well is created. In embodiments, seismic analysis may be performed surface, downhole, or both. In an exemplary embodiment, wireline operations are performed to obtain data relevant to the method described in connection with Figure 2. To this end, an overview of the wireline operations is provided to inform the reader of the equipment and methods used.

[0043] Wireline operations may be performed to acquire subsurface petrophysical and geophysical data associated with the formation 604 intersected by the wellbore. In these operations, a wireline truck 650 is provided. The wireline truck 650 is provided with a spool 652 that houses a cable 654. The cable 654 may be a single-strand or multi-strand cable unit. The cable 654 is configured to allow sensors and equipment to be lowered into the wellbore so that the sensors and equipment can perform the necessary investigations. The lowering operation may be accomplished by a motor 656 connected to the spool 652. Within the wireline truck 650, an operator can activate and stop the motor 656 and control the associated gearing to enable the spool 652 to unwind the cable 654 at a desired rate. A sensor 658 may be provided to verify the amount of cable 654 that has been unwound, allowing the operator to identify the location of equipment suspended by the cable 654.

[0044] The equipment supported by the cable may be a single equipment package or multiple equipment packages. In the case of multiple equipment packages, such equipment packages may be modular so that different types of packages can be added together according to the operator's needs. Different types of packages may include, but are not limited to: Packer System Pressure Gauge Test System Nuclear Measurement System Optical Spectroscopy Measurement System Pressure monitoring system Resistivity calculation system Sonic and ultrasonic tool systems ·Drilling hole seismic tool system Nuclear magnetic resonance tool system Pressure control system Tractor and exercise intensification system Power generation system Telemetry and data recording systems Computing Systems

[0045] Generally, the different modular systems described above may be added together as needed to form a logging tool 660, which may be called or known as a sonde. The logging tool 660 is lowered into the well to a desired point in the formation 604, and the appropriate systems are activated. The wireline operator may take sensor readings at one point, or may take multiple readings while changing the elevation of the logging tool 660. The resulting series of measurements may be referred to as a "log." Wireline operations may also be used to rehabilitate wells to increase hydrocarbon production. Such operations, known as rehabilitating or "workover," may involve increasing existing well parameters.

[0046] An objective of the presently disclosed embodiments is to provide a method for processing downhole sensor data to automatically obtain high-resolution and high-resolution interval velocity information without having to rely on lengthy (and often inaccurate, often manual) time selection. As an example, data can be included during a field investigation and then processed to allow for continued field activity. This capability is not currently possible with conventional techniques. There are various types of field analysis techniques. Figure 1 illustrates several types of techniques, including: (a) check-shot vertical seismic profile (VSP), (b) walk-away VSP, (c) microseismic profile, (d) walk-above VSP, (e) zero-offset VSP ("ZOVSP"), (f) single-well seismic profile, (g) offset VSP, (h) VSP amplitude versus offset (AVO) testing, (i) walk-around VSP, (j) SWD (seismic while drilling) testing, (k) cross-well seismic testing, (l) salt proximity testing, and (m) 3D VSP.

[0047] Considering the check-shot VSP and ZOVSP, the velocity along the wellbore (c) can be estimated from the arrival time selection of the direct P or S arrival using the following equation:

number

[0048] In embodiments, aspects of the described method are used to generate high-resolution velocity profiles. The method uses the relationship between strain amplitude and particle velocity to estimate c(z) (the high-resolution velocity profile) at a specific depth (z). The method does not rely on any time selection, and does not rely on tedious and relatively precise manual high-precision time selection. The method also does not rely on conventional automated arrival detection algorithms, which are prone to errors.

[0049] The theory behind the described method is beginning to emerge in the field of exploratory strain seismology, which has developed in connection with the interpretation of seismic datasets acquired using fiber optic cables (hDVS in SLB).

[0050] 2 illustrates a computational method 200 in one embodiment of the present disclosure. At 202, the method involves obtaining particle velocity data from a geological borehole seismic survey. At 204, the method also involves obtaining strain data associated with the geological borehole seismic survey. In one embodiment, the strain data may be associated with fiber optic data. In another exemplary embodiment, the strain data may be associated with simulation data. The method proceeds to 206 to calculate a peak-to-peak amplitude for the target phase. The method step of 206 follows the step of 202. At 208, the method provides for calculating a peak-to-peak amplitude for the target phase using the strain data at 204.

[0051] In aspects of the present disclosure, particle velocity and strain checkshot VSP data are obtained from field seismic activity at 202 and 204. For steps 202 and 204, sampling must be done at the same depth because the method requires seismic waveform amplitudes for each depth. The following data types may be used: Fiber optic data (industry-wide hDVS or DAS) · Simulated DAS data obtained from geophones.

[0052] As sources of geophone data, the following data types may be used at 202: Geophone recording Inverted particle velocity using the strain-to-velocity (STV) multiplexing method.

[0053] The next step involves calculating the peak-to-peak amplitude for the direct P arrivals (and S-wave arrivals, if available). At 206, 208, there is no need to define a time window for reading the peak-to-peak amplitudes, since the P wave is usually the largest amplitude arrival in the recording. In the case of noisy data, a time window may be defined, and the algorithm uses a priori knowledge of the P wave arrivals from various databases.

[0054] At 210, the phase velocity at depth z may be estimated as follows: c(z)=V_p2p(z) / D_p2p(z) Equation 1A

[0055] Considering the one-dimensional wave propagation problem applicable to check-shot VSP and ZOVSP, the following relations are established for infinitesimal strain and particle velocity:

number

number

[0056] The above equations are employed to convert infinite / finite strain data (epsilon, d) to particle velocity (v), but are not used to estimate phase velocity (c) using the infinite / finite strain (epsilon, d) and particle velocity (v) prior.

[0057] For example, if infinitesimal strain and particle velocity data are available, using equation (2), the phase velocity (c) is estimated as follows:

number

[0058] Equation 4 shows that the phase velocity at depth z can be estimated by dividing the amplitudes of the two seismic traces and is constant with respect to t. This equation is very difficult to apply because the amplitudes contain noise. To account for potential noise, amplitude information from the seismic data, such as peak-to-peak amplitude, is used. To estimate the velocity, Equation 5 uses the peak-to-peak amplitude within a specific time window that includes direct P-wave (and S-wave arrivals, if available).

number

[0059] 3A and 3B show the composite waveforms in the velocity and strain domains. In one embodiment, the P-wave is assumed to arrive within a time window of 250 msec to 1000 msec from the shot time.

[0060] Figure 4 shows the phase velocity 402 estimated by the method described in connection with Figure 2. Those from the conventional method using exact (theoretical) time selection are provided by the results listed in 400. The new method provides results comparable to the conventional method without using time selection.

[0061] In such an embodiment, referring to Figure 5, a computing device is used to control the equipment for performing the analysis steps described in Figure 2. In Figure 5, a processor 500 is provided to perform the computer analysis in response to provided instructions. The provided instructions, code, may be written to achieve a desired purpose, and the processor 500 has access to the instructions. In other embodiments, the instructions may be provided directly to the processor 500.

[0062] In other embodiments, other components may be used in place of a general-purpose processor. These specially designed components, known as application-specific integrated circuits ("ASICs"), are specifically designed to perform a desired task. As such, ASICs generally have a smaller footprint than general-purpose computer processors. When used in embodiments of the present disclosure, ASICs may use field-programmable gate array technology, allowing users to vary computing as needed. Thus, the methods described herein are not tied to any particular exact embodiment, but rather allow for programming changes to be achieved through these configurations.

[0063] In an embodiment, processor 500, if present, may have an arithmetic logic unit ("ALU") 502, a floating point unit ("FPU") 504, registers 506, and a single or multi-level cache 508. Arithmetic logic unit 502 may perform arithmetic and logic functions. Floating point unit 504 may be a math coprocessor or numeric coprocessor that manipulates numbers more efficiently and quickly than other types of circuitry. Registers 506 are configured to store data used by processor 500 during calculations, provide operands to arithmetic unit 502, and store results of operations. Single or multi-level cache 508 is provided as a repository of data that increases computation speed by preventing processor 500 from frequently accessing random access memory ("RAM") 514.

[0064] Aspects of the present disclosure provide for the use of a single processor 500. Other embodiments of the present disclosure allow for the use of multiple processors. Such configurations are sometimes referred to as multi-core processors, in which different functions are performed by different processors to facilitate computation speed. In embodiments, when different processors are used, computations may be performed simultaneously by the different processors, a process known as parallel processing.

[0065] The processor 500 may be located on a motherboard 510. The motherboard 510 is a printed circuit board that incorporates not only the processor 500 but also other components useful for processing, such as memory modules (“DIMMs”) 512, random access memory 514, read-only memory 515, non-volatile memory chips 516, a clock generator 518 that keeps components synchronized, and connectors for connecting other components to the motherboard 510. The motherboard 510 may have various sizes according to the needs of the computer architecture. For this purpose, its various sizes, known as form factors, may vary from the size of a mobile phone to the size of a desktop personal computer. The motherboard 510 may also provide other services that support the function of the processor 500, such as cooling capacity. The cooling capacity may include a thermometer 520 and a temperature-controlled fan 522 that directs cooling air over the motherboard 510 to reduce the temperature.

[0066] Data stored for execution by processor 500 may be stored in several places, including random access memory 514, read-only memory 515, flash memory 524, computer hard disk drive 526, compact disk 528, floppy disk 530, and solid state drive 532. For boot purposes, data may be stored in an integrated chip called an EEPROM that is accessed during start-up of processor 500. This data, known as the basic input / output system ("BIOS"), in some exemplary embodiments, contains the operating system which controls both internal and peripheral components.

[0067] Different components may be added to or connected to the motherboard to enhance processing. Examples of such connections for peripheral components may be video input / output sockets, storage configurations (such as hard disks, solid state disks, or access to cloud-based storage), printer communication ports, enhanced video processors, additional random access memory, and network cards.

[0068] The processor and motherboard may be provided in a separate form factor, such as a personal computer, a mobile phone, a tablet, a personal digital assistant, or other component. The processor and motherboard may be connected to other such similar computing devices in a networked manner. Data may be exchanged between different sections of the network to enhance the desired output. The network may be a public computing network or a secure network to which only authorized users or devices may be allowed access.

[0069] As will be apparent, the method steps for completion may be stored in random access memory, read-only memory, flash memory, computer hard disk drives, compact discs, floppy disks, and solid state drives.

[0070] Different input / output devices may be used with the motherboard and processor. Data input may be via keyboard, voice, Universal Serial Bus ("USB") devices, mouse, pen, stylus, FireWire, video camera, light pen, joystick, trackball, scanner, barcode reader, and touch screen. Output devices may include monitors, printers, headphones, plotters, televisions, speakers, and projectors.

[0071] Referring now to FIG. 7, a method 700 for obtaining a checkshot or zero-offset vertical seismic profile is disclosed. In step 702, one or more sensors (“receivers”) are placed in the borehole. In one or more embodiments, the receivers may be geophones or fiber optic sensors. In step 704, one or more seismic sources are placed outside the borehole at or near the borehole head. The one or more seismic sources may be vibrators, explosives, and / or air guns. Further, in step 706, seismic waves are propagated by the one or more seismic sources, and one or more receivers observe the seismic waves propagating along the borehole. The observation of the seismic waves by the one or more receivers may include particle velocity and strain data. This particle velocity and strain data can then be used to perform a fully automated high-resolution interval velocity estimation, as described above in FIG. 2.

[0072] Referring now to FIG. 8 , a method 800 for obtaining a walk-away, walk-above, or three-dimensional vertical seismic profile is disclosed. In step 802, one or more sensors (“receivers”) are placed in the borehole. In one or more embodiments, the receivers may be geophones or fiber optic sensors. In step 804, one or more seismic sources are placed on the surface, away from the borehole wellhead. In one or more embodiments, the one or more seismic sources may be placed along a line away from the borehole, thereby generating a walk-away vertical seismic profile. In other embodiments, the one or more seismic sources may be placed on the surface projected above the wellbore, thereby generating a walk-above vertical seismic profile. In other embodiments, the one or more seismic sources may be placed in a two-dimensional plane on the surface, thereby generating a three-dimensional vertical seismic profile. The one or more seismic sources may be vibrators, explosives, and / or air guns. Further, in step 806, seismic waves are propagated by the one or more seismic sources, and the propagated seismic waves are observed by one or more receivers. Observations of seismic waves from one or more receivers may include particle velocity and strain data, which can then be used to perform fully automated high-resolution interval velocity estimation, as described above in Figure 2.

[0073] Referring now to FIG. 9, a method 900 for acquiring a cross-well vertical seismic profile is disclosed. In step 902, one or more sensors (“receivers”) are placed in a borehole. In one or more embodiments, the receivers may be geophones or fiber optic sensors. In step 904, one or more seismic sources are placed in a second borehole. The one or more seismic sources may be vibrators, explosives, and / or air guns. Further, in step 906, seismic waves are propagated by the one or more seismic sources, and the one or more receivers observe the propagated seismic waves. The observation of the seismic waves by the one or more receivers may include particle velocity and strain data. The particle velocity and strain data can then be used to perform a fully automated high-resolution interval velocity estimation, as described above in FIG. 2.

[0074] In one or more embodiments, one or more sensors ("receivers") may be placed in a borehole to obtain a microseismic profile by observing seismic waves generated by earthquakes.

[0075] The following description provides a description related to measurements obtained during wireline operations as typically performed as described above. Obviously, various changes and modifications may be implemented while obtaining the desired measurements, and therefore the described method should not be considered limiting.

[0076] In one exemplary embodiment, a method is disclosed. The method may include testing and acquiring particle velocity data from at least one geological formation at a field location. The method may further include acquiring strain data from the at least one geological formation at the field location. The method may further include performing a peak-to-peak amplitude analysis on the particle velocity data of a target phase. The method may further include performing a peak-to-peak amplitude analysis on the strain data of the target phase. The method may further include estimating a wave velocity in the at least one geological formation based on the peak-to-peak amplitude analysis on the particle velocity data of the target phase and the peak-to-peak amplitude analysis on the strain data of the target phase.

[0077] In another exemplary embodiment, the method may be practiced where testing and acquiring strain data is acquired from a geophone.

[0078] In another exemplary embodiment, the method may be practiced where the strain data is from fiber optic data.

[0079] In another exemplary embodiment, the method may be practiced where particle velocity data is obtained from a geophone.

[0080] In another exemplary embodiment, the method may further include outputting the speed in the form of a log.

[0081] In another exemplary embodiment, the method may be implemented where the log is displayed as a chart.

[0082] In another exemplary embodiment, the method may be practiced where testing and obtaining particle velocity data from at least one formation at a field location and obtaining strain data from at least one formation at a field location are performed at one location.

[0083] In another exemplary embodiment, the method may be performed where one location has a specified depth.

[0084] In another exemplary embodiment, the method may be practiced where the strain data is simulated data.

[0085] In another exemplary embodiment, the method may be practiced where strain data is obtained through field testing.

[0086] In another exemplary embodiment, the method may be practiced where the velocity data is inverse particle velocity.

[0087] In another exemplary embodiment, the method may be implemented in which the inverse particle velocity is obtained using a strain-to-velocity multiplexing method.

[0088] In another exemplary embodiment, the method may be implemented in which the wave velocity is estimated by dividing the amplitudes of two seismic traces.

[0089] In another exemplary embodiment, the method may be implemented in which the wave velocity is estimated by the formula c(z)=V_p2p(z) / D_p2p(z).

[0090] In another exemplary embodiment, the method may be practiced where particle velocity data is obtained from a check shot vertical profile data set.

[0091] In another exemplary embodiment, the method may be practiced where particle velocity data is obtained from a walk-away vertical seismic profile.

[0092] In another exemplary embodiment, the method may be practiced where particle velocity data is obtained from a microseismic survey.

[0093] In another exemplary embodiment, the method may be practiced where particle velocity data is obtained from a walk-above vertical seismic profile.

[0094] In another exemplary embodiment, the method may be practiced where particle velocity data is obtained from a zero-offset vertical seismic profile.

[0095] In another exemplary embodiment, the method may be practiced where the particle data is obtained from a cross-well survey.

[0096] The description of the foregoing embodiments has been provided for purposes of illustration and description. It is not intended that the disclosure be exhaustive or limiting. Individual elements or features of a particular embodiment are generally not limited to that particular embodiment, but, where applicable, can be interchangeable and used in selected embodiments even if not specifically shown or described. The same may be modified in many ways. Such variations are not considered to be a departure from the disclosure, and all such modifications are intended to be included within the scope of the disclosure.

[0097] While embodiments have been described herein, it will be appreciated by those skilled in the art having the benefit of this disclosure that other embodiments are contemplated that do not depart from the scope of the present invention, and therefore the scope of this or any subsequent claims should not be unduly limited by the description of the embodiments set forth herein.

Claims

1. placing one or more sensors in a borehole; placing one or more seismic sources outside the borehole at or near the wellhead of the borehole at a field location; propagating seismic waves using the one or more seismic sources; acquiring particle velocity data from at least one formation at the field location; acquiring strain data from the at least one formation at the field location; performing a peak-to-peak amplitude analysis on the particle velocity data of a target phase; performing a peak-to-peak amplitude analysis on the strain data of the target phase; estimating a wave velocity in the at least one formation based on the peak-to-peak amplitude analysis of the particle velocity data of the target phase and the peak-to-peak amplitude analysis of the strain data of the target phase; A method comprising:

2. The one or more sensors are geophones 2. The method of claim 1 .

3. The one or more sensors are fiber optic sensors.

2. The method of claim 1 .

4. The velocity data is the inverse particle velocity 2. The method of claim 1 .

5. The inverse particle velocity is obtained using the strain-to-velocity multiplexing method.

2. The method of claim 1 .

6. The wave velocity is estimated by dividing the amplitudes of the two seismic traces 2. The method of claim 1 .

7. The wave velocity is estimated by the formula c(z)=V_p2p(z) / D_p2p(z).

2. The method of claim 1 .

8. The particle velocity data is obtained from a check shot vertical profile data set.

2. The method of claim 1 .

9. The particle velocity data is obtained from a zero-offset vertical seismic profile.

2. The method of claim 1 .

10. placing one or more sensors in a borehole; disposing one or more seismic sources outside the borehole at a field location away from the wellhead; propagating seismic waves using the one or more seismic sources; acquiring particle velocity data from at least one formation at the field location; acquiring strain data from the at least one formation at the field location; performing a peak-to-peak amplitude analysis on the particle velocity data of a target phase; performing a peak-to-peak amplitude analysis on the strain data of the target phase; estimating a wave velocity in the at least one formation based on the peak-to-peak amplitude analysis of the particle velocity data of the target phase and the peak-to-peak amplitude analysis of the strain data of the target phase; A method comprising:

11. The one or more seismic sources are positioned along a line away from the borehole.

11. The method of claim 10.

12. The one or more seismic sources are positioned outside the well projected above the borehole.

11. The method of claim 10.

13. The one or more seismic sources are arranged in a two-dimensional plane outside the borehole.

11. The method of claim 10.

14. The one or more sensors are geophones 11. The method of claim 10.

15. The one or more sensors are fiber optic sensors.

11. The method of claim 10.

16. The velocity data is the inverse particle velocity 11. The method of claim 10.

17. The inverse particle velocity is obtained using the strain-to-velocity multiplexing method.

11. The method of claim 10.

18. The wave velocity is estimated by dividing the amplitudes of the two seismic traces 11. The method of claim 10.

19. The wave velocity is estimated by the formula c(z)=V_p2p(z) / D_p2p(z).

11. The method of claim 10.

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