Multicomponent Vertical Seismic Profile Research Articles

Full-Waveform Inversion of Fiber-Optic VSP Data From Deviated Wells

Distributed acoustic sensing (DAS) technology permits measuring the strain or strain rate along a fiber deployed in a well due to seismic wave propagation. In vertical seismic profiling (VSP) acquisitions where seismic waves are excited at the surface and measured by subsurface receivers in the well, the DAS serves as a fast alternative to a conventional geophone array. Like conventional multicomponent VSP velocity measurements, DAS VSP data contain information about the subsurface properties that are encoded in seismic events and attributes such as compressional and shear direct arrivals, reflections, converted modes, multiples, and amplitude and phase variations. These seismic data can be used to obtain elastic properties of the formation and characterize the reservoir. Full-waveform inversion (FWI) extracts the elastic properties of the formation from the seismic wavefield by minimizing the misfit between real measurements and synthetically modeled wavefields. The synthetically generated wavefields are obtained by solving partial differential equations that accurately model the physical phenomena of the real waveforms. For conventional geophone sensors, FWI is formulated for the particle velocity field. In this paper, we present a formulation of the modeling and inversion specifically for DAS measurements as an averaged strain along the fiber. The algorithm does not require converting the data to velocities. The gradient of the misfit function, by adjoint formulation, is a cross correlation in time of the forward-propagated wavefield and backward-propagated residuals injected from the receivers. For conventional sensors, the residuals are injected as force terms, but for DAS data, the residuals are averaged in space first and then injected as moment tensor sources with radiation patterns determined by the well deviation. For multi-offset in-plane and out-of-plane VSP acquisitions, a two-dimensional (2D) algorithm has been developed that inverts for a 2D distribution of elastic medium properties and includes three-dimensional (3D) well deviation effects. This paper will present the results of applying the inversion to real multi-offset, highly out-of-plane VSP fiber data acquired in a deviated well. Simulations confirm that the well trajectory has a considerable impact on the data amplitude and must be included in the modeling and inversion to reproduce amplitude variations. The inverted compressional and shear velocities agree well with the reference model based on sonic data. Another real data example is a multi-offset walk-above acquisition where a targeted domain is located below a deviated portion of the well. The inversion matches reflections and produces an image in the target area.

Deep Learning-Based P- and S-Wave Separation for Multicomponent Vertical Seismic Profiling

Vertical seismic profiling (VSP) helps to derive high-resolution images around the instrumented borehole and is a cost-effective technique for CO₂ storage monitoring. In routine VSP data processing, P- and S-wave separation is a crucial step to extract independent single-mode waves for accurate imaging and interpretation. Conventional wave mode separation involves tedious, subjective, and non-reproducible manual interventions, especially when dealing with complex geology. To better automate the process, we propose a data-driven deep learning-based P- and S-wave separation method. Our method adapts a fully convolutional neural network that simultaneously extracts P- and S-potential data from multicomponent VSP measurements. To reduce the enormous computational cost in wave simulation while constructing training datasets with sufficient kinematic and dynamic variations, we introduce virtual wellbores where synthetic VSP data sampling wide variations in seismic kinematics and dynamics are recorded using only a dozen elastic wave simulations on a single velocity model. We qualify the separation results both directly in data space and in image space after reverse time migration (RTM). Generalization tests on various synthetic models and their corresponding RTM images demonstrate that the proposed strategy provides sufficient sampling of the high-dimensional data space and essentially ensures successful applications of the trained neural network to similar yet different geological scenarios.

Off-the-grid vertical seismic profile data regularization by a compressive sensing method

Different from the surface survey, the vertical seismic profile (VSP) survey deploys sources on the surface and geophones in a well. VSP provides higher resolution information of subsurface structures. The faults that cannot be imaged with surface seismic data may be detected with VSP data, and detailed analysis of fracture zones can be achieved with multicomponent VSP. However, one of the main problems is that the sources seldom are acquired on a regular grid in realistic VSP surveys. The irregular samplings cause serious artifacts in migration or imaging, such that data regularization must be implemented first. We have developed a compressive sensing (CS)-based method to regularize nonstationary VSP data. Our method directly operates on irregularly gridded data sets, which is a key contribution compared to the existing CS-based reconstruction methods that work on regular grids. The CS framework consists of a sparsity constraint and a penalty term. We have used the curvelet transform for sparsity constraint of nonstationary events in the regularization term and the nonequispaced Fourier transform to regularize the VSP data in a penalty term. An alternative directional method of multipliers is used for solving the optimization problem. Our method is tested on synthetic, field 2D and 3D VSP data sets. Our method obtains improved reconstructions on continuities of the events and produces fewer artifacts compared to the well-known antileaking Fourier transform method.

Correlation between seismic diffractions extracted from vertical seismic profiling data and borehole logging in a carbonate environment

Seismic diffractions may play an important role in seismic interpretation because they characterize geologic objects that might not be visible for conventional seismic attribute analysis. Diffractivity may be caused by, and consequently may define, tectonic dislocations (faults and fractures), lithologic variations, and fluid saturation within rocks. We have tied seismic diffractions extracted from vertical seismic profiling (VSP) data and borehole logging, from which we recognized the reasons that were responsible for diffractivity of the strata. First, we processed a multisource multicomponent VSP data set to extract seismic diffractions and constructed diffraction images of the strata for all three of the VSP data components. Then, we performed joint analysis of well logs and diffractions to obtain petrophysical attributes associated with diffraction images. We divided the rock succession into several units, which have different diffraction properties. We identified compacted rock, alternating intervals, isolated fractured zones, and fluid-saturated layers.

Inversion of multicomponent 3D vertical seismic profile data for porosity and CO2 saturation at the Cranfield injection site, Cranfield, MS

Studying how injected [Formula: see text] affects the seismic response of reservoir rocks is important because it can improve subsurface characterization where [Formula: see text] injection is taking place. This study uses multicomponent data from a 3D vertical seismic profile (VSP) and well logs to model and invert probabilistically for the porosity and [Formula: see text] saturation at the Cranfield reservoir. The well logs were used to calibrate a rock-physics model. Once the accuracy of the model was verified, P-impedance and [Formula: see text]/[Formula: see text] from inverted multicomponent VSP data were used to estimate the porosity and fluid saturation. This inversion generated probabilistic estimates of porosity and fluid saturation for the area of the reservoir sampled by PP- and PS-waves. Inversion results using the measured well log data for calibration indicated that the model was able to estimate porosity with a relatively high degree of accuracy, with the root-mean-square (rms) error being less than 3% for all calibration tests. Pore-fluid composition was estimated, however, with reduced accuracy, with rms errors ranging from 6% to 22% depending on the composition of the calibration fluid. Results from integrating the multicomponent VSP data with the rock-physics model indicated that estimated reservoir porosities are quite close to measured values at an observation well. Pore-fluid composition estimates indicated that this method can differentiate between areas containing [Formula: see text] and those that do not.

Sensitivity of estimated elastic moduli to completeness of wave type, measurement type, and illumination apertures at a receiver in multicomponent VSP data

Inversion of phase slowness and polarization vectors measured from multicomponent vertical seismic profile data can yield estimates of all 21 density-normalized elastic moduli for anisotropic elastic media in the neighborhood of each 3C geophone. Synthetic test data are produced by direct evaluation of the Christoffel equation, and by finite-difference solution of the elastodynamic equations. Incompleteness of the data, with respect to illumination (polar and azimuth angle) apertures (qP and/or qS) wave types, wave-propagation directions, and the amount of data (e.g., with or without horizontal slowness components), produces solutions with variations in quality, as revealed by the distribution of model parameter correlations. In a good solution, with all parameters well constrained by the data, the correlation matrix is diagonally dominant. qP-only and qS-only solutions typically produce complementary distributions in their correlation matrices, as they are orthogonal in their sampling of the medium with respect to polarization. The elastic moduli become less independent as the data apertures decrease. If the other input data are relatively complete, the horizontal components of the slowness vector are not needed as the information they contain is redundant. The main consequence of omitting horizontal slowness components is slower convergence. When modest amounts of random noise are added to the slowness and polarization data, in otherwise adequately sampled apertures, the solution is still very close to the correct model, but with larger residual variance.

Decoupling of deformation in the Upper Rhine Graben sediments. Seismic reflection and diffraction on 3-component Vertical Seismic Profiling (Soultz-sous-Forêts area)

A contribution to the definition of the structural pattern of the Soultz-sous-Forêts EGS (Enhanced Geothermal System) is presented here. After reprocessing, the PHN84J seismic reflection profile highlights the tilted blocks of the Merkwiller-Péchelbronn oilfield. In the Soultz-sous-Forêts horst, complex fault patterns are observed: the Hermerswiller normal fault flattens at depth and is rooted in decollements occurring in Triassic salt or clay series, while other steep normal faults affect underlying sedimentary formations and basement. Some methods for the exploitation of a seismic diffraction recorded by multi-component Vertical Seismic Profiling (VSP) are also illustrated to locate the diffractor without specific data processing. Polarisation and travel time analysis of a diffraction event recorded in the GPK1 borehole are analysed, and its exploitation combined with seismic reflection helps defining a tilted block geometry.

Multicomponent VSP imaging of tight-gas sands

Low-porosity Bossier and Cotton Valley sands of the East Texas Basin, U. S., have only a small acoustic impedance contrast with the encasing shales but a greater relative contrast in shear-wave impedance. Vertical seismic profile (VSP) data acquired with both a near-offset and far-offset P-wave source clearly demonstrate the P-P reflectivity and P-S mode conversions within the Bossier section. We designate conventional P-wave reflectivity as P-P, shear-wave reflectivity as S-S, and P-wave/shear-wave mode conversion data as P-S. While Bossier P-P reflectivity is low, it appears to be adequate for mapping thick sandbodies such as the York Sandstone, the main exploration target in this area. However, P-P reflectivity is even lower and is inadequate for imaging the overlying Cotton Valley Sands. In contrast, the far-offset VSP data acquired with a P-wave source demonstrate a high level of P-S-mode conversion, which is used to image this interval with definition that is not provided by P-P reflectivity. This provides strong support for the use of P-S-mode conversion imaging for seismic characterization of tight sand reservoirs. Near-offset shear-wave VSP data acquired with a shearwave source show low S/N ratio and limited bandwidth for the downgoing waveform because of the depth of the target; shear-wave energy appears to have a more limited range of propagation than P-waves. Such effects may also have a strong negative impact on multicomponent imaging of these sands using surface seismic techniques. Multicomponent 3D VSP imaging provides a superior solution by placing the geophones closer to the subsurface zone of interest.

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.

P- and S-wave characterization of near‐surface reflectivity from glacial tills using vertical seismic profiles

Fundamental reflectivity properties are established within the glacial deposits of central Saskatchewan, Canada. Multicomponent vertical seismic profile (VSP) data collected in three shallow boreholes are used to obtain detailed acoustic property information within the first 80 m of the near‐surface strata. The integration of both P- and S-wave VSP data, in conjunction with other borehole geophysics, provided a unique opportunity to obtain in‐situ seismic reflection response properties in layered clay and sand tills. P- and S-wave interval velocity profiles, in conjunction with P- and S-wave VSP reflectivities are analyzed to provide insight into seismic wavefield behavior within ∼80 m of the surface. In general, shear wave energy identifies more reflective intervals than the P-wave energy because of better vertical resolution for S-wave energy (0.75 m) compared to P-wave energy (2.3 m) based on quarter wavelength criterion. For these saturated, unconsolidated glacial deposits, more details about the lithologic constituents and in‐situ porosity are detectable from the S-wave reflectivity, but P-wave reflections provide a good technique for mapping the bulk changes. The principal cause of seismic reflectivity is the presence and/or amount of sand, and the degree of fluid‐filled porosity within the investigated formations.

Transformation of four-component vertical seismic profiling records from Kola superdeep borehole, Russia

Multicomponent vertical seismic profiling (VSP) provides valuable and reliable information about the geologic structure of the subsurface and is one of the best ways to study seismic anisotropy. However, some VSP tools have no orientation instrumentation, and additional preprocessing steps may be required. Using the example of the 1992 VSP survey on the Kola Superdeep Borehole, Russia, we describe a general approach to the data reduction for a VSP tool with any number of channels. Due to data redundancy provided by the four-component Kola VSP tool, we are able to increase signal-to-noise ratio, estimate coupling variations, perform geophone gain corrections, and carry out an additional quality control. We describe the computer implementation of the method based on the seismic processing system currently being developed. The program is able to apply tool-rotation correction based on the polarization properties of the first break. This rotation technique works well in the case of offset VSPs; whereas for zero-offset VSPs, we recommend more robust rotation procedure based on the use of the direct shear wave. We find that plotting of instantaneous polarization azimuths provides a useful device to control the performance of tool-correction approaches.

Processing of a nine‐component near‐offset VSP for seismic anisotropy

A convolutional sequence of matrix operators is offered as a convenient deterministic scheme for processing a multicomponent vertical seismic profile (VSP). This sequence is applied to a nine‐component near‐offset VSP recorded at the Conoco borehole test facility, Kay County, Oklahoma. These data are corrected for tool spin and near‐surface anisotropy together with source coupling or imbalance. After wave‐field separation using a standard f‐k filter, each source and receiver pair for the upgoing waves is adjusted to a common reference depth using a matrix operator based on the downgoing wave‐field. The up‐ and downgoing waves are then processed for anisotropy by a similarity transformation, to separate the [Formula: see text] and [Formula: see text] waves, from which the anisotropic properties are estimated. These estimates reveal a strong (apparent) vertical birefringence in the near‐surface, but weak or moderate values for the majority of the subsurface. The target zone consists of a thin sandstone and deeper shale layer, both of which possess a strong vertical birefringence. The sandstone corresponds to a zone of known fluid flow. An observed [Formula: see text] attenuation and polarization change in the shale suggest it contains large fractures.

Seismic anisotropy and natural fractures from VSP and borehole sonic tools—A field study

A multicomponent vertical seismic profile (VSP), cross‐dipole shear‐wave log, formation micro imaging (FMI) log, and oriented core were obtained in the Brady Ranch 1–5 well, Carter County, Oklahoma in November 1992. The intent was to study the properties of fractured intervals and the response of the seismic data with respect to fracture orientation. The primary zones of interest were the Sycamore and Hunton carbonates. A full nine‐component VSP was obtained from 152 to 3010 m. Data from a cross‐dipole shear‐wave log were obtained primarily in the deep carbonates at 2600–2900 m. The VSP and cross‐dipole data gave estimates of the orientation of azimuthal anisotropy in the section, and indicate three changes in the orientation of azimuthal anisotropy with depth. An east‐northeast orientation was obtained in the deepest zone, which includes the carbonate interval. The cross‐dipole data indicate anisotropy having east‐northeast, east‐south‐east, and approximately north‐south orientations in this zone. The cross‐dipole tool may be responding to small scale microcracks, which may have more random orientations than the larger scale macrofractures. FMI log data and oriented core, also obtained in the deep carbonate section, indicate macrofractures oriented in east‐northeast and east‐southeast directions.

North Sea reservoir description: Benefits of an elastic migration/inversion applied to multicomponent vertical seismic profile data

A linearized elastic migration/inversion (M/I) technique is applied to multicomponent offset VSP data collected in the North Sea. High‐resolution elastic images of the target zone (P- and S-wave velocities and density) are obtained from upgoing P-P and P-S wave fields. These M/I images are an approximate representation of rapid variations of subsurface parameters. Three image confidence criteria provide a measure of uncertainty in the interpretation. VSP-CDP transform maps assisted in the definition of the confidence region in M/I images. M/I was helpful in delineating the Brent reservoir, and detecting a twofault system. Preliminary interpretation indicates an increase in Poisson’s ratio at the top of the reservoir. Surface data were not able to image this target due to strong multiples at the Cretaceous base. This is the first time elastic depth images have been obtained from M/I of offset VSP field data. Generally, image artifacts depend on the following conditions: (1) good quality data with satisfactory coverage of the target zone; (2) accurate, amplitude‐preserving data preprocessing techniques for filtering out “unwanted” waves; and (3) an elastic background model which adequately represents the main subsurface features. Our M/I approach is flexible, since it can be used with single or multicomponent prestack data P-P, P-S, S-P, and S-S scattered waves simultaneously, an arbitrary acquisition geometry, and a two‐dimensional heterogeneous background model. Computational efficiency results from concentrating the inversion on a target zone and using the paraxial ray method to compute ray‐approximate Green’s functions.