Walkaway Vertical Seismic Profile Research Articles

Walkaway vertical seismic profiling first-arrival traveltime tomography with velocity structure constraints

Abstract Walkaway vertical seismic profiling (WVSP) is known for its high level of credibility in obtaining the relationship between first-arrival traveltime and detector depth through first-arrival picking. This relationship can be utilized for seismic velocity model inversion to improve velocity model accuracy and rationality. Here, we present a WVSP first-arrival velocity model with velocity structure constraints, by utilizing layer and fault data interpreted by ground seismic structure technique. We constructed a geological structure and layer sequence models based on sedimentary patterns to obtain complex velocity structures. Furthermore, we introduced a smooth regularization term based on the velocity structure into the inversion model to enhance its consistency with geological laws and compensate for the reduced inversion accuracy owing to the regularization term based on flat structures. This approach addressed the limitations of the regularization term based on flat structures, resulting in more accurate and reliable inversion results. Through simulation analysis, the proposed method realized the WVSP first-arrival velocity inversion, with results being closer to those of the real velocity model.

Inversion of walkaway VSP data in the presence of lateral velocity heterogeneity

Multi-azimuth walkaway vertical seismic profiling is an established technique for the estimation of in situ slowness surfaces and inferring anisotropy parameters. Normally, this technique requires the assumption of lateral homogeneity, which makes the horizontal slowness components at depths of downhole receivers equal to those measured at the surface. Any violations of this assumption, such as lateral heterogeneity or nonzero dip of intermediate interfaces, lead to distortions in reconstructed slowness surfaces and, consequently, to errors in estimated anisotropic parameters. In this work, we relax the assumption of lateral homogeneity and discuss how to correct vertical seismic profile data for weak lateral heterogeneity. We describe a procedure of downward continuation of recorded traveltimes that accounts for the presence of both vertical inhomogeneity and weak lateral heterogeneity, which produces correct slowness surfaces at depths of downhole receivers, noticing that sufficiently dense receiver coverage along a borehole is required to separate influences of vertical and lateral heterogeneity on measured traveltimes and obtain accurate estimates of the slowness surfaces. Once the slowness surfaces are found and a desired type of anisotropic model to be inverted is selected, the corresponding anisotropic parameters, providing the best fit to the estimated slownesses, can be obtained. We invert the slowness surfaces of P-waves for parameters of the simplest anisotropic model describing dipping fractures (transversely isotropic medium with a tilted symmetry axis). Five parameters of this model, namely, the P-wave velocity V0 in the direction of the symmetry axis, Thomsen's anisotropic coefficients ϵ and δ, the tilt ν, and the azimuth β of the symmetry axis, can be estimated in a stable manner when maximum source offset is greater than half of receiver depth.

Selecting velocity models using Bayesian Information Criterion

ABSTRACTWe present a strategy for selecting the values of model parameters by comparing walkaway vertical seismic profiling data with a multilayered model in the context of Bayesian information criterion. We consider P‐wave traveltimes and assume elliptical polar velocity dependence. A model with different propagation speeds, depending on the angle of propagation, can be a good approximation for a medium composed of thin layers. While elliptical anisotropy in a one‐layer model yields good results, an efficient tool for multilayer modelling would provide improved inversion results. To obtain the proper set of velocity values for specific parameterizations, we require two steps of optimization. In the first step, we find the signal trajectory; in the second step, we obtain parameter values by minimizing the misfit between the model and the data. By comparing models and data, we choose the best model in the sense of the Bayesian information criterion.

Case study on amplitude and phase response comparison between DAS and 3C geophone VSP surveys at a test site in Japan

Distributed acoustic sensing (DAS) is an effective tool for seismic surveys and is widely used as the preferred sensor for acquiring dense Vertical Seismic Profile (VSP). However, DAS has some disadvantages compared to conventional geophone acquisition, such as single-component data, sensor directivity pattern, low S/N, etc. To apply DAS data to VSP processing, it is important to understand the characteristics of DAS measurements. This study first examined DAS and geophone responses for a VSP survey in a 1D earth model. The relationship of signal amplitude as a function of incident angle and phase shift between wavelets was confirmed. Next, we validated this relationship in a walk-away VSP survey, which was conventionally applied to monitor geological CO2 storage. The survey was carried out at a test site in Japan. We obtained both three-component (3C) geophone and DAS data using a single-mode fiber installed behind a casing. The observed amplitudes of the first P-waves by DAS and geophone showed very good agreement with the theoretical expectations. Finally, we performed imaging using acquired DAS data following the workflow for conventional VSP processing. These basic behaviors of DAS are useful for designing further analyses, such as VSP in deviated wells and full waveform inversion.

Walkaway Vertical Seismic Profiling (WVSP) Modeling and Imaging Study along FaultedCoal Seams over a High Velocity Limestone Model: A Synthetic Study

The problem of collecting reflection data from the layers below a high velocity layer (HVL) and imaging those layers accurately is solved using walkaway vertical seismic profiling (WVSP) technique. The procedure is shown on a dataset from a model of highly faulted, thin-bedded coal layers separated by a high velocity layer of limestone. By locating the receivers above, in, and below the HVL, the reflections are expected to be recorded locally in situ in the borehole below the HVL before they travel back to the surface as in the case of surface seismic. The imaging results obtained from the model (or synthetic) WVSP data lead to the conclusion that promising results may be obtained via the acquisition of field WVSP data such that the layers below the HVL are well-imaged. Analysis of the test results showed that the layers below the HVL can be imaged accurately and robustly when the receivers are situated below the HVL only, while the strong images below the HVL tend to fade away and lose their strength when the receivers are moved above the HVL. However, both these cases of the receiver location geometry are needed to obtain images that are vertically and horizontally stable. When a full instrumentation of the borehole is provided, good images as far as 500 m away from the VSP borehole are obtained from the layers with various dips and faults that are nearly 800 m in depth from the surface. Two cases of velocities (4000 m/s and 5000 m/s) are tested for the high velocity limestone layer. Both cases showed good images below the HVL. Unfortunately, some pulled-up effects are seen in the images right below the HVL where the layers that are immediately below the HVL are imaged above their correct locations, the pulled-up effects are corrected in the deeper sections below the HVL however. Comparison of a depth converted corridor stack from the zero offset VSP data and the depth migrated image show good agreement.

Walkaway Vertical Seismic Profiling (WVSP) Modeling and Imaging Study along FaultedCoal Seams over a High Velocity Limestone Model: A Synthetic Study

The problem of collecting reflection data from the layers below a high velocity layer (HVL) and imaging those layers accurately is solved using walkaway vertical seismic profiling (WVSP) technique. The procedure is shown on a dataset from a model of highly faulted, thin-bedded coal layers separated by a high velocity layer of limestone. By locating the receivers above, in, and below the HVL, the reflections are expected to be recorded locally in situ in the borehole below the HVL before they travel back to the surface as in the case of surface seismic. The imaging results obtained from the model (or synthetic) WVSP data lead to the conclusion that promising results may be obtained via the acquisition of field WVSP data such that the layers below the HVL are well-imaged. Analysis of the test results showed that the layers below the HVL can be imaged accurately and robustly when the receivers are situated below the HVL only, while the strong images below the HVL tend to fade away and lose their strength when the receivers are moved above the HVL. However, both these cases of the receiver location geometry are needed to obtain images that are vertically and horizontally stable. When a full instrumentation of the borehole is provided, good images as far as 500 m away from the VSP borehole are obtained from the layers with various dips and faults that are nearly 800 m in depth from the surface. Two cases of velocities (4000 m/s and 5000 m/s) are tested for the high velocity limestone layer. Both cases showed good images below the HVL. Unfortunately, some pulled-up effects are seen in the images right below the HVL where the layers that are immediately below the HVL are imaged above their correct locations, the pulled-up effects are corrected in the deeper sections below the HVL however. Comparison of a depth converted corridor stack from the zero offset VSP data and the depth migrated image show good agreement.

Analysis, processing, and migration of the marine 4-component walkaway VSP data set from the SEG SEAM-1 Gulf of Mexico salt elastic modelling project: Synthetic study

The four component (4C) walkaway vertical seismic profile (WVSP) marine elastic synthetic data set from the SEG's SEAM-1 salt modeling project in the Gulf of Mexico (GOM) are examined, analyzed, processed, and migrated for P-P reflections using a reverse time prestack migration (RTM) algorithm to construct a subsurface image around the Well-1 VSP borehole. The imaging results from the three data sets; pressure-p, geophone vertical (z), and horizontal inline (x) components, have shown great successes in correctly locating and imaging sediments near and below the borehole as well as the vertical face of the salt, which is about 5 km away from the borehole. All major features of the salt body; from flat zones below the borehole to a vertical salt-face (with 90° dip), are imaged clearly by both the pressure (p) and the geophone z components. In the up-dip direction, the sediments are imaged nearly 3 km away from the borehole. Because of the differences in their frequency contents, the pressure-p and the geophone-z components are presented separately. Out of the three components (p, z, and x) the best image is obtained from the geophone vertical component due to its lesser noise content. Due to its sensitivity to horizontal motion, the horizontal geophone (x) seems to record a great amount of information from the waves traveling in more lateral or diagonal directions. A successful image of the salt face is also obtained with the x-component.

Joint PP, PS1, and PS2 AVA Inversion of HTI Media

Sedimentary strata formed by orientational vertical fractures are approximately equivalent to transversely isotropic media with a horizontal symmetry axis (HTI). Parameter inversion for the isotropic background and fracture parameters can provide valuable information for predicting fractured reservoirs. Following Bakulin’s modeling theory, we parameterized the HTI medium with the first- and second-order Lamé parameters of the isotropic background, host rock density, fracture density, and fracture azimuth. We calculated the fracture azimuth and separated split shear waves using the Alford rotation. Based on the exact reflection coefficients, we develop a joint P-to-P reflected wave (PP), PS1, and PS2 amplitude variation with angle (AVA) inversion method in the depth domain by using the second-order Levenberg–Marquardt (LM) algorithm to invert the remaining four parameters. Numerical model tests revealed that our method was more accurate compared to the traditional LM method and works for both weak/strong contrasts and anisotropy magnitudes. We used real data from the walkaway vertical seismic profiling (VSP) as an example to propose a set of strategies, thereby improving the practicality of our inversion method. To protect the fracture information contained in the wavefields, we adopted vector-feature-preserving data processing procedures to preprocess the field VSP data and separate PP, PS1, and PS2 reflections. We utilized P-wave first breaks to successfully discriminate and match these three wave modes from the same fractured formation in the depth domain; these were subsequently transformed to AVA gathers with ray tracing. We synthetically incorporated the time delays and layer velocities to build the initial models and to constrain the inversion process.

Fractured basement imaging using random-space-shift reverse time migration: A vertical seismic profile survey in the Bohai Bay Basin, China

Fractured basements are not only potential reservoirs for hydrocarbon resources, but they also provide significant storage space for carbon dioxide ([Formula: see text]) sequestration and radioactive waste disposal. However, fractured basements are challenging for seismic imaging methods due to the complexities in their fault and fracture networks, strong heterogeneity, highly variable structural dip, and strong impedance contrasts between the basement rocks and the surrounding sediments. We present a field case in which a walkaway vertical seismic profiling (VSP) survey was conducted at a fractured basement play located in the Bohai Bay Basin, China, to improve the resolution compared with a preexisting surface seismic profile. Using the advanced random-space-shift (RSS) reverse time migration (RTM), we obtain a high-resolution image with a clear delineation of the highly faulted dipping basement. From numerical and field examples, we find that the application of the RSS-RTM improves the final image by mitigating unavoidable errors in the migration velocity model, which would otherwise result in an unfocused image using the conventional RTM approach. In addition, we determine the importance of proper wavefield separation using 3C recordings, which is the key to ensuring the quality of the final image. With an optimized VSP imaging workflow, we provide an enhanced image for the fractured basement to support the geologic interpretations and development decisions.

DAS-VSP interferometric imaging: CO2CRC Otway Project feasibility study

Recent advancements in distributed acoustic sensing (DAS) technology open new ways for borehole-based seismic monitoring of CO2 geosequestration. Compared to 4D surface seismic monitoring, repeated vertical seismic profiling (VSP) surveys with DAS receivers considerably reduce the cost and invasiveness of time-lapse CO2 monitoring. However, standard borehole imaging techniques cannot provide the same level of reservoir illumination as 3D surface seismic. The performance of VSP imaging can be significantly improved with interferometric utilization of free-surface multiples. We have developed a feasibility study of interferometric imaging with a synthetic walkaway VSP data set, followed by its application to field walkaway VSP data recorded by conventional borehole geophones and two types of DAS (standard and engineered fibers). Both experiments (synthetic and field) demonstrate that interferometric imaging is a viable method to extend the subsurface image beyond the coverage of standard VSP imaging. Specifically, the interferometry approach provides a more detailed upper section of the subsurface, whereas standard migration of primary reflections provides a more detailed bottom part of the image. Comparison of the standard and engineered fibers indicates that both fibers are sensitive to free-surface multiples, but the engineered fiber provides a much higher signal-to-noise ratio; thus, it is preferable for interferometric imaging with multiples. The result obtained with the engineered DAS cable indicates that in the depth range suitable for both methods, the VSP interferometric image of the reflectors is comparable to the surface seismic image. The experiment on the field DAS data proves that DAS is sensitive enough to record the nonprimary wavefield for imaging and monitoring of the subsurface.

A Walkaway Vertical Seismic Profiling Modeling and Imaging Study and Combining Its Results with Migrated Surface Seismic Images

This paper presents and analyzes results from a Finite Difference Modeling (FDM), processing, and imaging study of a Walkaway Vertical Seismic Profiling (WVSP) survey, and discusses how the images from WVSP enhance those from the surface seismic data. It is shown that the results from the WVSP integrate well with the image from the surface seismic performed in the same line. For the study, a seismic model with vertically and horizontally varying velocities was built and a WVSP data set was generated. The surface seismic had difficulty to show clear images from the layers with steep dips and near vertical displacements on the model due to the lack of ray coverage. The study demonstrates that the WVSP geometry can record reflections from near vertical layers facing the borehole, which help with imaging the parts of the subsurface structure which were missing in the surface seismic. With proper combination of the images from the WVSP and the surface seismic, a more complete image profile of the subsurface can be constructed around the borehole. However, while contributing to surface seismic, it is also seen that the WVSP introduces more migration artifacts related to source interval distance and interbed multiples than the surface seismic data.

P-Wave-Only Inversion of Challenging Walkaway VSP Data for Detailed Estimation of Local Anisotropy and Reservoir Parameters: A Case Study of Seismic Processing in Northern Poland

In this paper, we present a detailed analysis of walkaway vertical seismic profiling (VSP) data, which can be used to obtain Thomsen parameters using P-wave-only inversion. Data acquisition took place in difficult field conditions, which influenced the quality of the data. Therefore, this paper also shows a seismic data processing scheme that allows the estimation of correct polarization angles despite poor input data quality. Moreover, we showed that it is possible to obtain reliable and detailed values of Thomsen’s anisotropy parameters for data that are challenging due to extremely difficult field conditions during acquisition and the presence of an overburden of salt and anhydrite (Zechstein formation). This complex is known for its strong seismic signal-attenuating properties. We designed a special processing workflow with a signal-matching procedure that allows reliable estimation of polarization angles for low-quality data. Additionally, we showed that P-wave-only inversion for the estimation of local anisotropy parameters can be used as valuable additional input for detailed interpretation of geological media, even if anisotropy is relatively low.

Elastic-waveform inversion and imaging of 2010 walkaway VSP data from the Raft River geothermal field

A vertical seismic profiling (VSP) survey conducted in 2010 in the original RRG-9 well at the Raft River geothermal field is to understand the subsurface geologic structures for geothermal reservoir characterization. This survey consists of 40 three-component (3C) geophones deployed in the upper 600 m of the well and 255 vibroseis sources positioned along eight walkaway lines at the surface. We perform elastic-waveform inversion and reserve-time migration of the VSP data to obtain high-resolution subsurface images. We first process the raw walkaway 3C VSP data and separate the upgoing compressional-to-compressional (PP) and compressional-to-shear (PS) wavefields. We then build an initial velocity model based on sonic logging and zero-offset VSP data, update the initial model with first-arrival traveltime tomography, and refine the model using elastic-waveform inversion to reveal high-resolution velocity variations. We finally apply reverse-time migration to the upgoing wavefields to obtain high-resolution PP and PS migration images of the lithologies encountered in the well. The refined velocity models obtained using elastic-waveform inversion improve the subsurface migration imaging results. Our elastic-waveform inversion and reverse-time migration confirm the lithology interfaces revealed from well logs and provide images of subsurface geologic layers away from well RRG-9 at the Raft River geothermal field.

Seismic imaging of a near-vertical vein using controlled-source seismic interferometry

New methodologies for narrow-vein mining are making thin, steeply dipping mineralized veins economically viable mining targets. Drilling is the normal method for delineation and resource evaluation prior to mining. However, for the evaluation of narrow veins, significant drilling of barren rock is required. Controlled-source seismic interferometry has the potential to significantly decrease the costs of target delineation by providing high-resolution seismic images of thin, steeply dipping mineralized veins. We present a case study that employs seismic interferometry in conjunction with a walkaway vertical seismic profiling survey to image a thin (0.5–4 m), steeply dipping barite vein. The footprint of the seismic data acquisition is relatively small and compatible with operations in areas with limited access (e.g., mining camps). The technique requires some care with experimental design and data processing, but it is clearly demonstrated to produce a high-resolution seismic image. Furthermore, we demonstrate that inversion of the depth-migrated image can be used to quantify vein thickness and provide direct information for resource evaluation and reserve estimation.

Parameterization analysis and field validation of VTI-elastic full-waveform inversion in a walk-away vertical seismic profile configuration

Elastic full-waveform inversion (FWI) in transversely isotropic media with a vertical symmetry axis (VTI) is applied to field walk-away vertical seismic profile (W-VSP) data acquired in Western Canada. The performance of VTI-elastic FWI is significantly influenced by the model parameterization choice. Synthetic analysis based on specific field survey configuration is carried out to evaluate three different VTI-elastic model parameterizations. Interparameter trade-offs are quantified using the recently introduced interparameter contamination sensitivity kernel approach. Synthetic results suggest that neglecting anisotropy leads to inaccurate velocity estimations. For the conventional vertical velocity-Thomsen’s parameter parameterization (i.e., vertical P-wave velocity, vertical S-wave velocity, Thomsen’s parameters [Formula: see text] and [Formula: see text]), a sequential inversion strategy is designed to reduce strong natural interparameter trade-offs. The model parameterizations of elastic-constant ([Formula: see text], [Formula: see text], [Formula: see text], and [Formula: see text]) and velocity-based (vertical, horizontal, and normal move-out P-wave velocities and vertical S-wave velocity) models appear to suffer from fewer interparameter trade-offs, providing more reliable velocity and anisotropy models. Results derived from application of VTI-elastic FWI to the field W-VSP data set tend to support the synthetic conclusions. Multiparameter point spread functions are calculated to quantify the local interparameter trade-offs of the inverted models. The output inversion results are interpreted to provide valuable references regarding the target hydrocarbon reservoir.

S-wave attenuation estimation from walkaway vertical seismic profiling data in methane hydrate-bearing sediments at Nankai Trough, Japan

Previous studies have demonstrated that the presence of methane hydrates (MHs) causes high S-wave attenuation (1/Q) at sonic logging frequencies. However, there are extremely few examples with which to estimate S-wave attenuation at seismic frequencies for MH reservoirs because of the low signal-to-noise ratio (SNR) of S-wave events. To elucidate the mechanisms responsible for such attenuation, it is important to obtain S-wave attenuation at various frequencies. We improve the SNR by horizontally stacking traces after linear moveout with fine-tuning over the offset range. Then we select better-quality S-wave events observed in methane hydrate-bearing sediment (MHBS). The better quality is possibly due to better coupling between the geophones and MHBS. Finally, we estimate S-wave intrinsic attenuation at a frequency range from 30 to 100 Hz from walkaway vertical seismic profiling (w-VSP) data. To isolate intrinsic attenuation from total attenuation, scattering attenuation is estimated using one-dimensional synthetic data from sonic velocity and density logs. The estimated intrinsic attenuation ranges from 0.34 to 0.39. By comparing our results with previously published results on S-wave attenuation at sonic frequencies of 0.5–1 kHz, we attribute a possible S-wave attenuation mechanism to the viscous friction due to the elastic contrast between hydrate and sand grains.

The value of VSP data through early phases of field appraisal and development: A modeling and acquisition case study in the Gulf of Mexico

The Gulf of Mexico is a rich hydrocarbon province that contains a diversity of petroleum systems play types. Often, identifying drilling targets can be challenging when solely using surface seismic data, particularly in areas with complex salt structures in the overburden. In this paper, we present a vertical seismic profile (VSP) modeling and acquisition case study for an oil field located in a subsalt, deepwater, ultrahigh-pressure high-temperature environment. Our objective was to model the subsurface to guide the acquisition of VSP data during the early phases of exploration and appraisal drilling. In the first exploration well, a salt-proximity VSP designed in a walkaway configuration was carried out to help better define the geometry of a salt overhang and verify anisotropy parameters, helping to reduce a critical uncertainty for imaging the subsalt structure across a large segment within our field area. In the first appraisal well, a zero-offset VSP was collected to establish a direct well tie and further calibrate our velocity model. In the second appraisal well, we utilized walkaway VSP data to form a high-frequency stratigraphic image between the two appraisal wellbores. These data were used to generate an enhanced image of the reservoir section that revealed subtle stratigraphic boundaries, another key subsurface uncertainty. Finally, we modeled both ambitious and conservative 3D VSP acquisition designs to understand the imaging area achieved through a 3D acquisition and undertook an assessment to understand the impact of PP and PS imaging for reservoir characterization. We conclude that VSP data are valuable tools in the early phases of field appraisal and development, and we demonstrate the business value of VSPs to optimize development drilling locations in our study area.

A field experiment of walkaway distributed acoustic sensing vertical seismic profile in a deep and deviated onshore well in Japan using a fibre optic cable deployed inside coiled tubing

ABSTRACTA two‐dimensional walkaway vertical seismic profiling survey using distributed acoustic sensing was conducted at an onshore site in Japan. The maximum depth and the deviation of the observation well were more than 4,000 m and 81 degrees, respectively. Among the several methods for installing fibre optic cables, we adopted the inside coiled tubing method, in which coiled tubing containing a fibre optic cable is deployed. The signal‐to‐noise ratio of the raw shot gather was low, possibly due to poor coupling between the fibre optic cable and the subsurface formation resulting from the fibre optic cable deployment method and the existence of considerable tubewave noise. Nevertheless, direct P‐wave arrivals, P–P reflections and P–S converted waves exhibited acceptable signal‐to‐noise ratios after careful optimization of gauge length for distributed acoustic sensing optical processing and the application of carefully parameterized tubewave noise suppression. One of the challenges in current distributed acoustic sensing vertical seismic profile data processing is the separation of P‐ and S‐waves using only one‐component measurements. Hence, we applied moveout correction using two‐dimensional ray tracing. This process effectively highlights only reflected P‐waves, which are used in subsequent subsurface imaging. Comparison with synthetic well seismograms and two‐dimensional surface seismic data confirms that the final imaging result has a sufficiently high quality for subsurface monitoring. We acquired distributed acoustic sensing vertical seismic profile data under both flowing conditions and closed conditions, in which the well was shut off and no fluid flow was allowed. The two imaging results are comparable and suggest the possibility of subsurface imaging and time‐lapse monitoring using data acquired under flowing conditions. The results of this study suggest that, by adopting the inside coiled tubing method without drilling a new observation well, more affordable distributed acoustic sensing vertical seismic profile monitoring can be achieved in fields such as CO2 capture and storage and unconventional shale projects, where monitoring costs have to be minimized.

Frequency-dependent reflection wave-equation traveltime inversion from walkaway vertical seismic profile data

To accurately image the geologic structures from walkaway vertical seismic profile (VSP) data, it is necessary to estimate the subsurface velocity field with high resolution and enhanced illumination of deep reservoirs. Because full-waveform inversion (FWI) suffers from cycle skipping when the initial model is far from the true model, we have adopted frequency-dependent reflection wave-equation traveltime inversion (FRWT) to generate the background velocity model for VSP migration. The upgoing reflection data are separated from the original shot gathers, and dynamic warping is used to evaluate the traveltime differences between the observed data and the calculated data. Different frequency bands of the data are inverted in sequence to reconstruct the velocity model with higher resolution. We also implement wavefield decomposition on the gradient field to extract the contributions of reflection components and improve the updated model. The inverted results obtained from FRWT can be used as the initial model for conventional FWI or the velocity model for reverse time migration. The experiments on synthetic data and field data demonstrate that our approach can effectively recover the background velocity model from walkaway VSP data.

Amplitude-based misfit functions in viscoelastic full-waveform inversion applied to walk-away vertical seismic profile data

Viscoelastic full-waveform inversion is applied to walk-away vertical seismic profile data acquired at a producing heavy-oil field in Western Canada for the determination of subsurface velocity models (P-wave velocity [Formula: see text] and S-wave velocity [Formula: see text]) and attenuation models (P-wave quality factor [Formula: see text] and S-wave quality factor [Formula: see text]). To mitigate strong velocity-attenuation trade-offs, a two-stage approach is adopted. In Stage I, [Formula: see text] and [Formula: see text] models are first inverted using a standard waveform-difference (WD) misfit function. Following this, in Stage II, different amplitude-based misfit functions are used to estimate the [Formula: see text] and [Formula: see text] models. Compared to the traditional WD misfit function, the amplitude-based misfit functions exhibit stronger sensitivity to attenuation anomalies and appear to be able to invert [Formula: see text] and [Formula: see text] models more reliably in the presence of velocity errors. Overall, the root-mean-square amplitude-ratio and spectral amplitude-ratio misfit functions outperform other misfit function choices. In the final outputs of our inversion, significant drops in the [Formula: see text] to [Formula: see text] ratio (~1.6) and Poisson’s ratio (~0.23) are apparent within the Clearwater Formation (depth ~0.45–0.50 km) of the Mannville Group in the Western Canada Sedimentary Basin. Strong [Formula: see text] (~20) and [Formula: see text] (~15) anomalies are also evident in this zone. These observations provide information to help identify the target attenuative reservoir saturated with heavy-oil resources.