Walkaway Vertical Seismic Profile Data Research Articles

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.

Estimation of seismic attenuation and prediction of VTI anisotropy parameters from VSP and log data: a case study from the Middle East

Quantitative interpretation of seismic data depends upon the amplitude analysis of reflected waves. However, the quality of the image obtained can be significantly affected by attenuation and anisotropy in the overburden. Therefore, the insights into the magnitude, sources and spatial distribution of these parameters may prove to be substantial for improving the quality of seismic image and reservoir characterisation. Both seismic vertical transverse isotropy (VTI) anisotropy and scattering attenuation could be caused by the layering. In order for these phenomena to play a major role, strong elastic contrasts between them are needed. In this paper, we present the case study from a typical setting in the Middle East where such a contrast between stiff carbonates and relatively soft siliciclastic sediments significantly deteriorates the quality of the seismic image. Vertical seismic profiling (VSP) and log data from one of the wells in the region are used to demonstrate this phenomenon. Apparent attenuation from VSP data is estimated using a modified centroid frequency shift method. The log data for seismic forward modelling is used in order to show that scattering could be a significant contributor to the apparent attenuation. In addition, by using both Backus averaging and synthetic walk-away VSP data analysis, we demonstrate that the same layering can be responsible for a significant TI anisotropy.

Velocity analysis with vertical seismic profile data using migration of surface-related multiples

We have developed an original method for migration velocity analysis for vertical seismic profile (VSP) data. The method is based on VSP imaging with the primary reflected data and surface-related multiples. Velocity updates are carried out by matching the images obtained by these two types of waves. To do it automatically, we have introduced an objective function of the crosscorrelation type and developed a gradient-based maximization algorithm. On synthetic walk-away VSP data sets, we found that maximization of the crosscorrelation of the images provided by the two different types of waves allowed the retrieval of the interval velocities below the borehole receivers — a problem that was considered to be challenging with a VSP acquisition. Also, the possibility of the lateral velocity gradient reconstruction was developed on a simple synthetic model. On the real walk-away VSP data set from the North Sea, we found that the method could also be used for estimation of effective anisotropy parameters below the borehole receivers. In all of our examples, the velocity model refinement based on the presented method led to significant improvements of the seismic images.

Vertical seismic profile migration velocity analysis via residual moveout in receiver domain common image gathers

The success of imaging vertical seismic profile (VSP) data critically depends upon obtaining and using an accurate subsurface velocity model. First-arrival-time tomography can be used to derive velocities above the receivers. Reflection time tomography can be used to derive velocities below the receivers, but it requires reflection time picking and association with appropriate horizons. We described an alternative, faster way to perform velocity analysis by assessing the residual moveout after migrating walk-away VSP data. We have derived residual moveout equations for migrated common receiver gathers assuming a constant velocity model with a single horizontal reflector. The observed residual moveout in common image gathers in the receiver domain will be aligned and flat if the migration velocity is correct. If the residual moveout is not flat, by digitizing the extreme point on the unstacked, migrated traces in each common receiver gather, we could invert for the velocity of the target layer using our new residual moveout equations. We then extended this method to handle depth and laterally varying layer geometries using an iterative root-mean-square velocity scheme and a layer-stripping strategy. We combined the power of a prestack VSP depth migration using complicated velocity structures with straightforward velocity updating equations. For a range of synthetic cases and geometries, the estimated velocities were within 3% of the actual value.

Anisotropic elastic full-waveform inversion of walkaway vertical seismic profiling data from the Arabian Gulf

ABSTRACT Borehole seismic addresses the need for high‐resolution images and elastic parameters of the subsurface. Full‐waveform inversion of vertical seismic profile data is a promising technology with the potential to recover quantitative information about elastic properties of the medium. Full‐waveform inversion has the capability to process the entire wavefield and to address the wave propagation effects contained in the borehole data—multi‐component measurements; anisotropic effects; compressional and shear waves; and transmitted, converted, and reflected waves and multiples. Full‐waveform inversion, therefore, has the potential to provide a more accurate result compared with conventional processing methods. We present a feasibility study with results of the application of high‐frequency (up to 60 Hz) anisotropic elastic full‐waveform inversion to a walkaway vertical seismic profile data from the Arabian Gulf. Full‐waveform inversion has reproduced the majority of the wave events and recovered a geologically plausible layered model with physically meaningful values of the medium.

Estimation of Thomsen’s anisotropic parameters from walkaway VSP and applications

Estimation of Thomsen’s anisotropic parameters is very important for accurate time-to-depth conversion and depth migration data processing. Compared with other methods, it is much easier and more reliable to estimate anisotropic parameters that are required for surface seismic depth imaging from vertical seismic profile (VSP) data, because the first arrivals of VSP data can be picked with much higher accuracy. In this study, we developed a method for estimating Thomsen’s P-wave anisotropic parameters in VTI media using the first arrivals from walkaway VSP data. Model first-arrival travel times are calculated on the basis of the near-offset normal moveout correction velocity in VTI media and ray tracing using Thomsen’s P-wave velocity approximation. Then, the anisotropic parameters δ and ɛ are determined by minimizing the difference between the calculated and observed travel times for the near and far offsets. Numerical forward modeling, using the proposed method indicates that errors between the estimated and measured anisotropic parameters are small. Using field data from an eight-azimuth walkaway VSP in Tarim Basin, we estimated the parameters δ and ɛ and built an anisotropic depth-velocity model for prestack depth migration processing of surface 3D seismic data. The results show improvement in imaging the carbonate reservoirs and minimizing the depth errors of the geological targets.

Walkaway VSP - Going beyond imaging

Simultaneous AVO inversion of seismic data is an integral part of oil and gas exploration. Traditionally this technique is applied to surface seismic data, relying on availability of various angle stacks as well as on presence of offset wells for low frequency models. This paper investigates how a Walkaway Vertical Seismic Profile (WVSP) can be utilized for localized AVO inversion. Traditionally WVSP are designed for one of the following three purposes: imaging, anisotropy and AVO/AVA analysis. This paper shows a set of conditions that allow for WVSP data to be inverted following a commonly utilized simultaneous seismic inversion technique. The advantage of performing a localized WVSP AVO inversion is that low frequency models are measured during WVSP acquisition. This significantly reduces the ambiguity of the background models for inversion. Another advantage is that the inversion input derived during WVSP migration comes from measured vertical velocities, thus allowing more accurate angle stacks, thus improving the quality of the inversion. Lastly, WVSP images are generally of higher frequency content, thus producing high frequency density, Acoustic Impedance and VpVs images in the vicinity of the wellbore. The results can assist in calibrating the surface seismic inversion once more well data are available as well as making quick drilling decisions for deepening or side tracking wells.

Reliability of the slowness and slowness-polarization methods for anisotropy estimation in VTI media from 3C walkaway VSP data

We studied the validity of qP-wave slowness and slowness-polarization methods for estimating local anisotropy parameters in transversely isotropic (TI) media by quantifying the estimation errors in a numerical exercise. We generated numerical slownesses and polarizations over two aperture ranges corresponding to a short offset walkaway vertical seismic profiling (VSP) and a long offset walkaway VSP for a range of TI models with vertical axis of symmetry (VTI). Synthetic data are equisampled over the phase angle range and contaminated with Gaussian noise. We inverted the data and compared the anisotropy parameters of the optimal model with the true model. We found that the selection of a proper methodology for VTI parameter estimation based on walkaway VSP measurements was mostly dependent on our ability to accurately estimate either horizontal components of qP-wave slowness vector or the polarization vector. With data contaminated with noise, methods that include the horizontal component of the slowness vector had greater accuracy than the methods that replace this information with polarization measurements. The estimations are particularly accurate when a wide range of propagation angle was available. For short offsets, only parameter [Formula: see text] could be reliably estimated. In the absence of long offsets, depending on the accuracy of polarization measurements, the method based on the weak anisotropy approximation for qP-wave velocity in VTI media or the method based on slowness and polarization vectors could be used to estimate [Formula: see text] and [Formula: see text]. If the horizontal components of the slowness vector were not available (a heterogeneous overburden), we used methods that were based on local measurements of the polarization vector. We found that, with accurate measurements of the polarization vector, the method based on exact relationship between vertical slowness and polarization dip could be used to estimate VTI parameters even for the cases in which the wide offset range was not available.

Geometrical considerations in the acquisition of borehole interferometric data for imaging near-vertical features: Design of field experiments

Seismic interferometry applied to walkaway vertical seismic profile data has significant potential for imaging the steeply dipping structures often encountered in hard-rock minerals exploration. Using the interferometry process, surface shots can be redatumed to the borehole receivers resulting in virtual shot gathers. The virtual shot gathers can then be processed using a standard common midpoint (CMP) processing flow. Carrying out this procedure for a subvertical borehole results in a geometry that is optimal for imaging structures that are near vertical. Field acquisition parameters play a critical role in recovering reliable virtual source images. We evaluated the major factors that play a role in designing a field acquisition program with the objective of providing guidance to field practitioners. The major issue to be considered is insuring that correlation gathers created in the interferometry process have a stationary phase component that when summed produces events with correct timing and cancellation of nonstationary components. Consistent with previous work, the ray-tracing-based analysis identified the surface source spacing, surface source aperture, and dominant frequency as the most critical parameters. The analysis indicated that because of the high apparent velocities typically encountered in hard rock terrains, a surface source spacing of 20 m and an aperture of 1000 m will result in stationary phase components and avoid spatial alias in the correlation gathers for frequencies as high as 80 Hz. However, closer spacing of the surface sources provided more traces in the correlation gathers resulting in fewer artifacts during summation. These results were further verified by acoustic wave modeling that provided data from more complex targets that were processed through a complete interferometry and CMP flow. The analysis indicated that with care in designing field acquisition parameters, seismic interferometry is realizable within the terrain and access restrictions imposed by many mining camps.

Evaluation and joint inversion of TTI velocity models with walkaway VSP in deep-water offshore Angola

We present a case study where a multitude of walkaway vertical seismic profiling (WVSP) data was employed in evaluating the accuracy of anisotropic velocity models used in a prestack depth migration (PSDM) project. We integrated the WVSP traveltimes with surface seismic PSDM residual moveout on migrated common-image gathers (CIG) in a joint inversion that determined the anisotropic model parameters. The resulting anisotropic model significantly reduces the mis-ties between the modeled and observed first arrivals in the various WVSP lines, in addition to the enhancement in CIG flatness and significant im-provement in imaging.

Amplitude Variation with Offset Responses Modeling Study of Walkaway Vertical Seismic Profile Data at CO2 Geological Storage Site, Ketzin, Germany

An important component of any CO(2) sequestration project is seismic monitoring for tracking changes in subsurface physical properties, such as velocity and density. Different reservoirs have diffe ...

Amplitude Variation with Offset Responses Modeling Study of Walkaway Vertical Seismic Profile Data at CO2Geological Storage Site, Ketzin, Germany

Abstract:An important component of any CO2sequestration project is seismic monitoring for tracking changes in subsurface physical properties, such as velocity and density. Different reservoirs have different amplitude variation with offset (AVO) responses, which can define underground conditions. In the present paper we investigate walkaway vertical seismic profile (VSP) AVO response to CO2injection at the Ketzin site, the first European onshore CO2sequestration pilot study dealing with research on geological storage of CO2. First, we performed rock physics analysis to evaluate the effect of injected CO2on seismic velocity using the Biot‐Gassmann equation. On the basis of this model, the seismic response for different CO2injection saturation was studied using ray tracing modeling. We then created synthetic walkaway VSP data, which we then processed. In contrast, synthetic seismic traces were created from borehole data. Finally, we found that the amplitude of CO2injected sand layer with different gas saturations were increased with the offset when compared with the original brine target layer. This is the typical class III AVO anomaly for gas sand layer. The AVO responses matched the synthetic seismic traces very well. Therefore, walkaway VSP AVO response can monitor CO2distribution in the Ketzin area.

1D viscoelastic waveform inversion for Q structures from the surface seismic and zero-offset VSP data

Wave attenuation is an important physical property of hydrocarbon-bearing sediments that is rarely taken into account in site characterization with seismic data. We present a 1D viscoelastic waveform inversion scheme for determining the quality factor [Formula: see text] from the normal-incidence surface seismic and zero-offset vertical seismic profile (VSP) data simultaneously. The joint inversion problem is solved by the damped least-squares method, and the inversion result is successful using synthetic data. The effects of initial model thickness, [Formula: see text] value, and the existence of noise were studied through a synthetic example. By extracting all of the information contained in the waveforms, the waveform inversion of the seismic reflection and transmission data becomes a powerful tool for estimating [Formula: see text]. For a more comprehensive image of [Formula: see text], the tomographic inversion of [Formula: see text] is applied to the walkaway VSP and prestack surface seismic data, using the waveform inversion result as the initial model. Results from applying the method to a real seismic line and zero-offset VSP data from the Nanyang oilfield, central China, indicate that [Formula: see text] from the tomographic inversion of reflection and transmission data contains useful information on medium properties, which can aid in reservoir appraisal.

Virtual shear source makes shear waves with air guns

We demonstrate a novel application of the virtual source method to create shear-wave sources at the location of buried geophones. These virtual downhole sources excite shear waves with a different radiation pattern than known sources. They can be useful in various shear-wave applications. Here we focus on the virtual shear check shot to generate accurate shear-velocity profiles in offshore environments using typical acquisition for marine walkaway vertical seismic profiling (VSP). The virtual source method is applied to walkaway VSP data to obtain new traces resembling seismograms acquired with downhole seismic sources at geophone locations, thus bypassing any overburden complexity. The virtual sources can be synthesized to radiate predominantly shear waves by collecting converted-wave energy scattered throughout the overburden. We illustrate the concept in a synthetic layered model and demonstrate the method by estimating accurate P- and S-wave velocity profiles below salt using a walkaway VSP from the deepwater Gulf of Mexico.

Positioning drill-bit and look-ahead events using seismic traveltime data

We study seismic traveltime measurements acquired in the borehole, including vertical seismic profiling, seismic measurements while drilling, and drill-bit noise generated data. These traveltime data are used to assess informative parameters, including drill-bit position, distance to drilling target, and parameters of the velocity model. First, we analyze seismic traveltime data using a simple hyperbolic traveltime equation for rays between surface sampling locations and the drill bit. Second, we describe a model for estimating both the position of the drill bit and the relative distance to geologic interfaces ahead of the bit. Finally, we present a dynamic Bayesian strategy for real-time prediction of drill-bit positions, velocity parameters, and distances to geologic markers. Walk-away vertical seismic profiling data from the Norwegian Sea are used to demonstrate our methods. For this data set, we pick five key reflectors ahead of the drill bit. The deepest reflector is estimated to be [Formula: see text] ahead of the drill bit, using seismic traveltime data alone. The effects of aperture and surface sampling locations are large on our estimates and their associated uncertainties, and we observe that large offset is preferable to dense sampling in terms of positioning accuracy.

Monte‐Carlo Bayesian look‐ahead inversion of walkaway vertical seismic profiles

ABSTRACTWe describe a method to invert a walkaway vertical seismic profile (VSP) and predict elastic properties (P‐wave velocity, S‐wave velocity and density) in a layered model looking ahead of the deepest receiver. Starting from Bayes's rule, we define a posterior distribution of layered models that combines prior information (on the overall variability of and correlations among the elastic properties observed in well logs) with information provided by the VSP data. This posterior distribution of layered models is sampled by a Monte‐Carlo method. The sampled layered models agree with prior information and fit the VSP data, and their overall variability defines the uncertainty in the predicted elastic properties. We apply this technique first to a zero‐offset VSP data set, and show that uncertainty in the long‐wavelength P‐wave velocity structure results in a sizable uncertainty in the predicted elastic properties. We then use walkaway VSP data, which contain information on the long‐wavelength P‐wave velocity (in the reflection moveout) and on S‐wave velocity and density contrasts (in the change of reflectivity with offset). The uncertainty of the look‐ahead prediction is considerably decreased compared with the zero‐offset VSP, and the predicted elastic properties are in good agreement with well‐log measurements.

Inversion of multicomponent, multiazimuth, walkaway VSP data for the stiffness tensor

Vertical seismic profiling (VSP), an established technique, can be used for estimating in‐situ anisotropy that might provide valuable information for characterization of reservoir lithology, fractures, and fluids. The P‐wave slowness components, conventionally measured in multiazimuth, walkaway VSP surveys, allow one to reconstruct some portion of the corresponding slowness surface. A major limitation of this technique is that the P‐wave slowness surface alone does not constrain a number of stiffness coefficients that may be crucial for inferring certain rock properties. Those stiffnesses can be obtained only by combining the measurements of P‐waves with those of S (or PS) modes.Here, we extend the idea of Horne and Leaney, who proved the feasibility of joint inversion of the slowness and polarization vectors of P‐ and SV‐waves for parameters of transversely isotropic media with a vertical symmetry axis (VTI symmetry). We show that there is no need to assume a priori VTI symmetry or any other specific type of anisotropy. Given a sufficient polar and azimuthal coverage of the data, the polarizations and slownesses of P and two split shear (S1 and S2) waves are sufficient for estimating all 21 elastic stiffness coefficients cijthat characterize the most general triclinic anisotropy. The inverted stiffnesses themselves indicate whether or not the data can be described by a higher‐symmetry model.We discuss three different scenarios of inverting noise‐contaminated data. First, we assume that the layers are horizontal and laterally homogeneous so that the horizontal slownesses measured at the surface are preserved at the receiver locations. This leads to a linear inversion scheme for the elastic stiffness tensor c. Second, if the S‐wave horizontal slowness at the receiver location is unknown, the elastic tensor c can be estimated in a nonlinear fashion simultaneously with obtaining the horizontal slowness components of S‐waves. The third scenario includes the nonlinear inversion for c using only the vertical slowness components and the polarization vectors of P‐ and S‐waves. We find the inversion to be stable and robust for the first and second scenarios. In contrast, errors in the estimated stiffnesses increase substantially when the horizontal slowness components of both P‐ and S‐waves are unknown. We apply our methodology to a multiazimuth, multicomponent VSP data set acquired in Vacuum field, New Mexico, and show that the medium at the receiver level can be approximated by an azimuthally rotated orthorhombic model.

Seismic characterization of vertical fractures described as general linear‐slip interfaces

ABSTRACTFluid flow in many hydrocarbon reservoirs is controlled by aligned fractures which make the medium anisotropic on the scale of seismic wavelength. Applying the linear‐slip theory, we investigate seismic signatures of the effective medium produced by a single set of ‘general’ vertical fractures embedded in a purely isotropic host rock. The generality of our fracture model means the allowance for coupling between the normal (to the fracture plane) stress and the tangential jump in displacement (and vice versa). Despite its low (triclinic) symmetry, the medium is described by just nine independent effective parameters and possesses several distinct features which help to identify the physical model and estimate the fracture compliances and background velocities. For example, the polarization vector of the vertically propagating fast shear wave S1 and the semi‐major axis of the S1‐wave normal‐moveout (NMO) ellipse from a horizontal reflector always point in the direction of the fracture strike. Moreover, for the S1‐wave both the vertical velocity and the NMO velocity along the fractures are equal to the shear‐wave velocity in the host rock.Analysis of seismic signatures in the limit of small fracture weaknesses allows us to select the input data needed for unambiguous fracture characterization. The fracture and background parameters can be estimated using the NMO ellipses from horizontal reflectors and vertical velocities of P‐waves and two split S‐waves, combined with a portion of the P‐wave slowness surface reconstructed from multi‐azimuth walkaway vertical seismic profiling (VSP) data. The stability of the parameter‐estimation procedure is verified by performing non‐linear inversion based on the exact equations.

Multicomponent Kirchhoff migration

This paper presents a method for elastic and viscoelastic imaging of multicomponent seismic data. The method is based on Claerbout’s survey‐sinking concept and the (visco)elastic Kirchhoff integral for the displacement field. Assuming a multishot and multireceiver experiment, the migration process is formulated as a wavefield reconstruction problem, using the (visco)elastic Kirchhoff integral twice. First, the receiver coordinates are downward continued. Second, the source coordinates are downward continued. The multicomponent seismic data are treated as a vector wavefield in which the data measurements may be displacement velocity or traction (pressure). The theoretical formulation is based on the viscoelastic Hooke’s law and Newton’s equation of motion as the physical model for seismic wave propagation. It is valid for linear viscoelastic media with any anisotropic symmetry. When the lowest‐order ray approximation is introduced, the migration equation takes a form similar to conventional Kirchhoff migration. To obtain the imaging equations, the downward‐continued wavefield is related to the ray‐Born approximation. Numerical results are shown from elastic imaging of synthetic and real marine walkaway vertical seismic profiling (VSP) data.

Elastic reverse time migration of marine walkaway vertical seismic profiling data

Walkaway vertical seismic profiling (VSP) acquisition with three‐component geophones allows for direct measurement of compressional as well as shear energy. This makes full elastic reverse time migration an attractive alternative for imaging data. We present results from elastic reverse time migration of a marine walkaway VSP acquired offshore Norway. The reverse time migration scheme is based on a high‐order finite‐difference solution to the two‐way elastic wave equation. Depth images of the subsurface are constructed by correlation of forward‐ and back‐propagated elastic wavefields. In the walkaway VSP configuration, the number of shots is much larger than the number of geophone levels. Using processing methods operating in the shot/receiver domain, it is advantageous to use the reciprocal relationship between the walkaway VSP and the reverse VSP configurations. We do this by imaging each component of each geophone level as a reverse VSP common shot gather. The final images are constructed by stacking partial images from each level. The depth images obtained from the vertical components reveal the major characteristics of the geological structure below geophone depth. A graben in the base Cretaceous unconformity and a faulted coal layer can be identified. The horizontal components are more difficult to image. Compared to the vertical components, the horizontal component images are more corrupted by migration artifacts. This is because the horizontal component images are more sensitive to aperture effects and to the shear‐wave velocity macromodel. When converted to two‐way time, the migration results tie well with the surface seismic section. Comparison of fully elastic and acoustic reverse time migration shows that the vertical component is dominantly PP-reflected events, whereas the horizontal components get important contributions from PS-converted energy. The horizontal components also provide higher resolution because of the shorter wavelength of the shear waves.