Walkaway Vertical Seismic Profile Data Research Articles

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.

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.

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.

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.

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.

Estimation of in situ anisotropy parameters from two perpendicular walkaway VSP lines in South Pars field

Abstract Vertical phase slowness and polarization angle are the in situ parameters of P-wave propagation that can be derived from walkaway vertical seismic profiling (VSP) data. To use these data for estimating anisotropy parameters, we obtain an explicit equation of vertical slowness as a function of polarization angle for P-wave propagation in transversely isotropic with vertical symmetry axis (VTI) media. We use this equation to estimate anisotropy parameters of a target layer in the South Pars field, Iran. This field is one of the world's largest gas fields. We show that the orthorhombic symmetry is a reasonable assumption for this layer, providing some geological and petrophysical information. Two walkaway VSP lines along the symmetry axes of the presumed orthorhombic layer are used to estimate its parameters. Seven is the maximum number of parameters that can be estimated using P-wave data in this acquisition pattern. Of those estimated parameters are six of the Tsvankin style parameters for orthorhombic media, plus an approximate combination of two others that define vertical S-wave splitting. We show that a previous method, which is based on weak anisotropy approximation, leads to considerable errors, even in models where the magnitude of anisotropy parameters do not exceed 0.1. We design a numerical experiment to study the reliability of the estimated parameters by the exact approach and show the importance of acquisition pattern in this regard. To show applicability, these parameters are used to estimate the in situ fracture properties of the studied layer.

Imaging high-resolution velocity and attenuation structures from walkaway vertical seismic profile data in a carbonate reservoir using visco-acoustic waveform inversion

Frequency domain visco-acoustic waveform inversion is applied to multi-offsets vertical seismic profile data acquired over a carbonates reservoir in an oil field offshore Abu Dhabi in the United Arab Emirates, to produce high resolution seismic velocity and attenuation structures. The starting velocity and attenuation models are obtained from traveltime tomography, and from the centroid frequency-shift method, respectively. Waveform tomography is performed between the frequencies 4 and 50 Hz. To reduce coupling between velocity and attenuation parameters during model updates, a two stage inversion strategy is adopted. During the first stage, only the velocity model is recovered and, during the second stage, velocity and attenuation models are recovered. The density is estimated from empirical correlation derived from sonic and density logs at the borehole location. A judicious selection of the time-damping constant [Formula: see text], used to suppress late arrivals in the Laplace-Fourier domain is critical to mitigate nonlinearities. Prior to the inversion, data preconditioning is done to transform the data in a form convenient for the visco-acoustic wave equation. High resolution final velocity and attenuation models are obtained. Extracted 1D profiles from the final models generally correlate well with the sonic log and estimated clay content from the gamma-ray log. These observations give confidence to the results. A comparison of the synthetic data generated from the final models and the field data shows a high degree of similarity. The high resolution of the results enables us to readily identify layers and provide a geologic interpretation from Quaternary to Late Jurassic. The inverted models show a stack of layers with alternating relatively high and low velocity values associated with relatively high- and low-attenuation values defining anticlines, as we progressed deeper into the subsurface. The two main reservoirs units in the Lower Cretaceous are clearly identified.

VSP polarization angles determination: Wysin-1 processing case study

In this paper, we present an analysis of borehole seismic data processing procedures required to obtain high-quality vertical stacks and polarization angles in the case of walkaway VSP (vertical seismic profile) data gathered in challenging conditions. As polarization angles are necessary for more advanced procedures like anisotropy parameters determination, their quality is critical for proper media description. Examined Wysin-1 VSP experiment data indicated that the best results can be obtained when rotation is performed for each shot on data after de-noising and vertical stacking of un-rotated data. Additionally, we proposed a procedure of signal matching that can substantially increase data quality.

Borehole seismic survey using multimode optical fibers in a hybrid wireline

Distributed Fiber Optic Sensing is increasingly recognized as a viable alternative to geophone arrays for the acquisition of borehole seismic data. The ability to deploy optical fibers into a well, either as a cable based intervention or as part of a completion string, allows for the entire wellbore to be surveyed with every source activation. This can dramatically reduce the operating time required to complete a normal survey as well as offering the opportunity to achieve much higher spatial coverage than is typical of current technologies. The ability to acquire borehole seismic data in a producing well without the need to disrupt production also offers significant benefits to the operator.Distributed acoustic sensing (DAS) is a novel technology that uses an optical fiber cable as a sensor for acoustic signals and can take almost any downhole fiber-optic installation or deployment and turn the fiber optic cable into a large downhole seismic array. This array can provide enhanced Vertical Seismic Profile (VSP) imaging and monitor fluids and pressures changes in the hydrocarbon production reservoir. Walkaway VSP data acquired over a former producing well in north eastern China provided a rich set of very high quality DAS Walkaway VSP data. A standard VSP data pre-processing workflow was applied, followed by prestack Kirchhoff time migration. In the DAS pre-processing step we were faced with additional and special challenges: strong coherent noise due to cable slapping and ringing along the borehole casing. In comparison with an earlier offset VSP data set using 327-levels acquired with conventional 3C downhole geophones in the same well, the final pre-processed DAS walkaway VSP has a larger vertical aperture resulting in a wider lateral image. The single well DAS Walkaway VSP images provide a good result with higher vertical and lateral resolution than the surface seismic in the objective area. The vertical well environment without the ability to effectively “clamp” the sensor to the borehole casing wall by touching, creates a unique set of challenges. Although earth signal was recorded with almost all the shots, there was also a considerable amount of noise. Much of the noise was due to the physical placement of the wireline in the well and expressed by slapping and ringing. This paper reports on lessons learned in the handling of the wireline cable and subsequent special DAS data processing steps developed to remediate some of the practical wireline deployment issues. Optical wireline cable as a conveyance of fiber optic cables for VSP in vertical wells will open the use of the DAS system to much wider applications.

Imaging high-resolution seismic velocity from walkaway vertical seismic profile data in a carbonate reservoir using acoustic waveform tomography

High-resolution seismic velocity was obtained using acoustic full-waveform tomography of walkaway vertical seismic profile (VSP) data from an oil field dominated by carbonate rocks, offshore Abu Dhabi in the United Arab Emirates. The data were collected in a deviated borehole with receivers located from 521 to 2742 m depth. The inversion was performed in the frequency domain. The success of the inversion was determined by three important factors: the starting model, the preconditioning of the input data, and the inversion strategy, which included an appropriate selection of a damping term [Formula: see text] in the Laplace–Fourier transformation. The inversion was performed between the frequencies of 4 and 50 Hz, and a logarithmic data residual was used. The extracted 1D velocity profiles from the final high-resolution velocity model correlate well with the sonic log, and estimated vertical incidence VSP velocities. The predicted data obtained by the final velocity model indicate a generally good fit with the field data, thus confirming the success of the inversion. A reverse time migrated section derived by the final velocity model provides additional structural details. The velocity model indicates anomalous zones of low-velocity values that correlate with known locations of hydrocarbon reservoirs.

Elastic full-waveform inversion and parametrization analysis applied to walk-away vertical seismic profile data for unconventional (heavy oil) reservoir characterization

Elastic full-waveform inversion and parametrization analysis applied to walk-away vertical seismic profile data for unconventional (heavy oil) reservoir characterization

The derivation of an anisotropic velocity model from a combined surface and borehole seismic survey in crystalline environment at the COSC-1 borehole, central Sweden

The Scandinavian Caledonides provide a well-preserved example of a Palaeozoic continent–continent collision, where surface geology in combination with geophysical data provides information about the geometry of parts of the Caledonian structure. The project COSC (Collisional Orogeny in the Scandinavian Caledonides) investigates the structure and physical conditions of the orogen units and the underlying basement with two approximately 2.5 km deep cored boreholes in western Jämtland, central Sweden. In 2014, the COSC-1 borehole was successfully drilled through a thick section of the Seve Nappe Complex. This tectonostratigraphic unit, mainly consisting of gneisses, belongs to the so-called Middle Allochthons and has been ductilely deformed and transported during the collisional orogeny. After the drilling, a major seismic survey was conducted in and around the COSC-1 borehole with the aim to recover findings on the structure around the borehole from core analysis and downhole logging. The survey comprised both seismic reflection and transmission experiments, and included zero-offset and multiazimuthal walkaway Vertical Seismic Profile (VSP) measurements, three long offset surface lines centred on the borehole, and a limited 3-D seismic survey. In this study, the data from the multiazimuthal walkaway VSP and the surface lines were used to derive detailed velocity models around the COSC-1 borehole by inverting the first-arrival traveltimes. The comparison of velocities from these tomography results with a velocity function calculated directly from the zero-offset VSP revealed clear differences in velocities for horizontally and vertically travelling waves. Therefore, an anisotropic VTI (transversely isotropic with vertical axis of symmetry) model was found that explains first-arrival traveltimes from both the surface and borehole seismic data. The model is described by a vertical P-wave velocity function derived from zero-offset VSP and the Thomsen parameters ε = 0.03 and δ = 0.3, estimated by laboratory studies and the analysis of the surface seismic and walkaway VSP data. This resulting anisotropic model provides the basis for further detailed geological and geophysical investigations in the direct vicinity of the borehole.

Walkaway VSP using multimode optical fibers in a hybrid wireline

Distributed acoustic sensing (DAS) is a novel technology that uses an optical fiber cable as a sensor for acoustic signals and can take almost any downhole fiber-optic installation or deployment and turn the fiber-optic cable into a large downhole seismic array. This array can provide enhanced vertical seismic profile (VSP) imaging and monitor fluids and pressure changes in the hydrocarbon-production reservoir. Walkaway VSP data acquired over a formerly producing well in northeastern China provided a rich set of high-quality DAS walkaway VSP data. A standard VSP data preprocessing workflow was applied, followed by prestack Kirchhoff time migration. In the DAS preprocessing step, we were faced with additional challenges: strong coherent noise due to cable slapping and ringing along the borehole casing. Compared with an earlier offset VSP data set using 327 levels acquired with conventional 3C downhole geophones in the same well, the final preprocessed DAS walkaway VSP has a larger vertical aperture, resulting in a wider lateral image. The single-well DAS walkaway VSP images provide a good result with higher vertical and lateral resolution than the surface seismic in the objective area. The vertical-well environment, which lacks the ability to effectively “clamp” the sensor to the borehole-casing wall by touching, creates a unique set of challenges. Although earth signal was recorded with almost all the shots, there was also a considerable amount of noise. Much of the noise was due to the physical placement of the wireline in the well and was expressed by slapping and ringing. Reported here are lessons learned in handling the wireline cable and subsequent special DAS data processing steps developed to remediate some of the practical wireline deployment issues. Optical wireline cable as a conveyance of fiber-optic cables for VSP in vertical wells will open the use of the DAS system to wider applications.