Zero-offset Vertical Seismic Profile Data Research Articles

A Vertical Seismic Profiling Wavefield Separating Method Based on the Frequency-Wavenumber Vector

The separation of up-going and down-going wavefields is a significant step in the vertical seismic profiling (VSP) data processing. The traditional frequency-wavenumber (FK) transform method maps the VSP signal from the time-space domain to the FK domain for separation. However, the FK transform method cannot separate the wavefields well near the reflecting surface. In this paper, we propose a novel method called frequency-wavenumber vector classification (FKVC) to separate up-going and down-going wavefields from 2-D VSP data. First, we use the curvelet transform (CT) to extract the direction information of the VSP signal. CT is a tight frame and has multi-direction characteristics, so it can sparsely represent the signal in the curvelet domain. Although the shape of the curvelet window will cause some energy diffusion, synchrosqueezed curvelet transform (SSCT) can reassign the curvelet coefficients at the 2-D reference instantaneous frequency (IF) to improve the resolution. Then we extract the frequency-wavenumber vector (FKV) of the up-going and down-going wavefields respectively based on SSCT. Finally, the up-going and down-going wavefields can be separated by the angular difference of FKV. Both the synthetic example and real zero-offset VSP data example demonstrate the effectiveness of the proposed method. Compared with the FK transform method, the FKVC has a better separation result.

A Novel Method for Determining Geophone Orientations From Zero-Offset VSP Data Constrained by Scalar Field

In vertical seismic profile (VSP) acquisition, the orientation of the three-component geophones in a borehole is often not aligned due to random rotation of the wireline receiver array. Knowing the geophone orientation is crucial for rotating the waveforms back to the position where the geophones are assumed to be aligned. This procedure is critical in three-component VSP data processing as it provides the correct wavefields for subsequent VSP data imaging and inversion. For zero-offset or near zero-offset VSP measurements, the direct P-wave propagates nearly vertically, and the horizontal geophones receive only a small fraction of the direct P-wave energy. The first-arrival in the horizontal component data is often of low signal-to-noise ratio (SNR). As a result, it is difficult to apply conventional first-arrival–based methods for obtaining accurate geophone orientations. On the other hand, a seismic event comprising individual waveform would achieve maximum correlation if all corresponding geophones are aligned. The geometric characteristics, that is, the slope and continuity of a seismic event in the vector wavefield are the same with those of the modules of the vector wavefield. The latter, also known as the scalar wavefield, can be used for scanning geophone orientations based on waveform correlation. In this study, we propose to use the scalar field to extract the slope of seismic events. The orientation of the individual geophone was calculated with the constraint of the slope. We use both synthetic and field data to demonstrate the effectiveness and applicability of the proposed method. The results show that the new method can provide wavefields of horizontal component VSP data with much higher accuracy and resolution.

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.

Joint waveform inversion with the separated upgoing and downgoing wavefields of VSP data

Abstract Waveform inversion of Vertical Seismic Profiling (VSP) data, including upgoing and downgoing wavefields, is a challenging technique for building an accurate model. During the inversion process, upgoing and downgoing wavefields have different contributions to the objective function due to an energy imbalance between them that may cause the upgoing field to not be used effectively. Therefore, we propose a method of joint waveform inversion with the separated upgoing and downgoing wavefields of VSP data based on the establishment of a multiobjective function without introducing weight coefficients. The separating step with direct simulation of upgoing and downgoing wavefields of VSP data by the reflectivity method simplifies the complexity of separating wavefields. Specially, the zero-offset VSP data can be obtained in the τ−p domain to reduce computational cost greatly. Establishment of a multiobjective function of the difference between upgoing and downgoing wavefields can overcome the energy imbalance problem for them. The joint inversion step with a multiobjective optimization method avoids insufficient or incomplete information from just using an upgoing or downgoing wavefield alone. Numerical tests applied on synthetic models indicate that this method has the potential to increase the accuracy of estimating the velocity and density.

Assessment of gas hydrate accumulations using velocities derived from vertical seismic profiles and acoustic log data in Krishna-Godavari Basin, India

The second Indian National Gas Hydrate Program Expedition (NGHP-02) was executed in 2015 in four areas termed as Areas A, B, C and E. During this expedition, twenty five research sites were drilled and/or cored in Krishna-Godavari (KG) and Mahanadi Basins, eastern Indian offshore. During NGHP-02, zero offset vertical seismic profile (VSP) data were acquired at three sites: Sites NGHP-02-17, −19 and −22 in Area B of the KG Basin. In this study, we focus on the three sites in Area B of the KG Basin, where, zero-offset VSP and downhole acoustic log data are used to assess and characterize the gas hydrate deposits. Zero-offset VSP data are correlated with wireline log, surface seismic and synthetic seismic data to characterize and delineate gas hydrate accumulations in the KG Basin. Low velocities ranging from 1500 to 1650 m/s are observed in the unconsolidated shallow sedimentary section above gas hydrate-bearing units, whereas, very high velocities are observed in the acquired acoustic log and VSP data. In the gas hydrate-bearing sedimentary sections, the VSP derived interval velocities range from 2000 to 3000 m/s in the depth interval between 267 and 287 m below sea floor (mbsf) at Site NGHP-02-17, between 1650 and 1750 m/s in the depth interval between 306 and 366 mbsf at Site NGHP-02-19 and between 1700 and 1800 m/s in the depth interval between 198 and 290 mbsf at Site NGHP-02-22. Gas hydrates are distributed both as pore-filling and fracture-filling at all three sites, however, high concentrations are only observed as pore-filling morphology. We estimate the amount of gas hydrate considering both isotropic (pore-filling) and anisotropic (fracture-filling) acoustic reservoir models. Our estimations of gas hydrate saturation match well with the available pressure core data and suggest that high gas hydrate concentrations (to nearly 85% of pore space) are distributed in a load bearing morphology.

Cognitive seismic data modelling based successive differential evolution algorithm for effective exploration of oil-gas reservoirs

A cognitive modelling based new inversion method, the successive differential evolution (DE-S) algorithm, is proposed to estimate the Q factor and velocity from the zero-offset vertical seismic profile (VSP) record for oil-gas reservoir exploration. The DE algorithm seeks optimal solutions by simulating the natural species evolution processes and makes the individuals become optimal. This algorithm is suitable for the high-dimensional nonseparable model space where the inversion leads to recognition and prediction of hydrocarbon reservoirs. The viscoelastic medium is split into layers whose thicknesses equal to the space between two successive VSP geophones, and the estimated parameters of each layer span the related subspace. All estimated parameters span to a high dimensional nonseparable model space. We develop bottom-up workflow, in which the Q factor and the velocity are estimated using the DE algorithm layer by layer. In order to improve the inversion precision, the crossover strategy is discarded and we derive the weighted mutation strategy. Additionally, two kinds of stopping criteria for effective iteration are proposed to speed up the computation. The new method has fast speed, good convergence and is no longer dependent on the initial values of model parameters. Experimental results on both synthetic and real zero-offset VSP data indicate that this method is noise robust and has great potential to derive reliable seismic attenuation and velocity, which is an important diagnostic tool for reservoir characterization.

An Iterative Zero-Offset VSP Wavefield Separating Method Based on the Error Analysis of SVD Filtering

Wavefield separation is one critical step in the vertical seismic profiling (VSP) data processing. In this letter, we present an iterative zero-offset VSP wavefield separating method based on analyzing the error of the singular value decomposition (SVD) low-pass filtering. The error of the SVD low-pass filtering can be divided into the incomplete error and the truncated error. The incomplete error is caused by the incompleteness of subspace, while the truncated error is related to discarding small singular values and corresponding eigenimages. Flattening the strongly correlated component in the 2-D signal can reduce these two errors, and the flattened component can be extracted precisely with the SVD low-pass filtering. The zero-offset VSP data set in seismic data processing records downgoing and upgoing wavefields, which have different propagating directions. By flattening the downgoing and upgoing wavefields alternatively, we propose one iterative zero-offset VSP wavefield separating method. In each iteration, we first flatten the downgoing wavefield to increase its correlation and estimate the downgoing wavefield by using the SVD low-pass filtering, and then, we flatten the upgoing wavefield in the residual to increase its correlation and estimate the upgoing wavefield by using the SVD low-pass filtering. The proposed method is applied to one synthetic data set and one real zero-offset VSP data set. Compared with the commonly used wavefield separation method, our method can have better separation results and reduce the separation error.

Seismic quality factor estimation using frequency-dependent linear fitting

The estimation of the quality factor (Q factor) is very important for seismic data attenuation compensation and hydrocarbon indication. If both random noise and seismic signal co-exist, the logarithmic spectrum ratio (LSR) method, known as a popular method for Q estimation, is usually unstable and brings large errors. In order to improve the accuracy and stability of LSR method, in this paper, we propose an improved method for Q estimation by introducing frequency-dependent linear fitting (FDLF) in the spectral ratio method. We first use nonstationary linear fitting to estimate many Q factors, and then utilize the median value of these estimated Q values as the final estimation of Q factor. Using median value can effectively overcome the difficulties in effective frequency band selection in LSR method. The estimated cumulative Q can be transformed into interval layer Q. The proposed method can help to obtain more precise and stable result especially when the seismic data contains noise. We use synthetic and field zero-offset vertical seismic profile data examples to illustrate our method.

A novel method for separating intrinsic and scattering attenuation for zero-offset vertical seismic profiling data

A novel method for separating intrinsic and scattering attenuation for zero-offset vertical seismic profiling data

Q factor estimation based on the method of logarithmic spectral area difference

We have developed a novel method for [Formula: see text] estimation. As a seismic wave propagates through subsurface viscoelastic media, seismic attenuation decreases the amplitude and reduces the bandwidth, which leads to variation of the logarithmic spectral area of seismic wave. According to this property, we have derived an analytical relation between [Formula: see text] factor and the logarithmic spectral area difference of seismic wave. To improve the accuracy of [Formula: see text] estimation, we took account of the amplitude loss due to energy partitioning from transmission. Tests of the method on synthetic models determined the validity of our method, and it was insensitive to different types of noises and evaluated density. A further comparison between the presented method and two widely used [Formula: see text] estimation methods, namely, the logarithmic spectral ratio and centroid frequency shifting methods, with a synthetic model containing random noise demonstrated that our method is the more robust, in these situations, among the three approaches. Then, we also compared the effect of bandwidth and time-window selection on the [Formula: see text] estimation for these three methods, and the result revealed that our method is less sensitive to the bandwidth and time window than the other two methods. Application of this method to real zero-offset vertical seismic profile data shows a reasonable correlation between estimated interval-[Formula: see text] and interval velocities, which further indicates the validity of the method.

How frequency dependency of Q affects spectral ratio estimates

Because seismic amplitudes can be affected by purely geometrical factors, attenuation is often estimated not from amplitudes but from the evolution of the amplitude spectra of the waveform. Such estimation methods (e.g., the spectral ratio method and the centroid frequency shift method) assume that the quality factor [Formula: see text] is constant (independent of frequency) in the frequency band of the signal. If this assumption is violated, then [Formula: see text] estimates become biased. In particular, when the frequency dependency of [Formula: see text] is a power law [Formula: see text], then [Formula: see text] is systematically under- or overestimated by a factor of [Formula: see text]. The errors are larger for larger values of [Formula: see text], particularly when [Formula: see text] is negative. In particular, if [Formula: see text], the frequency content of the signal does not change, and [Formula: see text] is estimated to be infinite, regardless of the true value of [Formula: see text]. To avoid these systematic errors, it is necessary to monitor the evolution of frequency content and amplitude with distance. Zero-offset vertical seismic profile data from the North West Shelf of Australia revealed the decay of the signal amplitude with depth that can be explained by a combination of intrinsic constant [Formula: see text] and a frequency-independent factor, which in turn is caused by the geometric spreading plus transmission loss due to variations of acoustic impedance on a scale larger than the dominant wavelength in the signal.

Estimation of seismic attenuation from zero-offset VSP acquired in hard rock environments

Understanding of seismic attenuation plays an important role in successful application of seismic imaging and subsurface characterisation techniques based on amplitude analysis. Zero-offset vertical seismic profiling (VSP) is one of the principal tools which can be used to study seismic attenuation.Apparent attenuation estimated from seismic data analyses comprises of scattering and intrinsic components. Scattering mechanism can play significant role in hard rock environments in areas associated with fracture zones or other complex structures. As such seismic attenuation can be an important seismic exploration attribute.Meanwhile attenuation analyses from VSP data are almost routinely done in oil and gas industry they are still uncommon in mineral exploration.In this study we analyse zero-offset VSP data acquired in Western Australia on one of DET CRC test sites using both hydrophones and 3C geophones as receivers. We compare several methods for apparent attenuation estimation and evaluate their applicability to VSP data acquired in crystalline rocks. Extensive wire line log coverage for the well allows us to investigate relative contribution of different attenuation mechanisms.

Zero-offset vertical seismic profiling survey and estimation of gas hydrate concentration from borehole data from the Ulleung Basin, Korea

Gas hydrate has been receiving much attention in recent years as the demand for energy has increased. Before an economic evaluation of the feasibility of producing gas hydrate can be made, an assessment of reserves must be completed. To evaluate a reserve of gas hydrate, we should accurately know the depth interval of the gas hydrate-bearing region and the concentration of gas hydrate in it. Because vertical seismic profiling (VSP) data can provide higher resolution than surface seismic data, we can improve the reliability of the characterization of the gas hydrate-bearing region using VSP data along with surface seismic data.In this study, we obtained interval velocities and corridor stacked sections from zero-offset VSP data acquired at the UBGH2-6 and UBGH2-10 wells in gas hydrate-bearing zones of the Ulleung Basin, East Sea of Korea. The interval velocities obtained from the zero-offset VSP data agreed well overall with sonic logs and showed a significant decrease at the depth beneath the gas hydrate stability zone. Most reflection events in the corridor stacked section matched well those in the surface migrated seismic section. Additionally, we computed the concentration of the gas hydrate from the log data using a three-phase Biot-type equation, and the result agreed well with the concentration calculated from the resistivity log using Archie's equation.

Application of Gabor deconvolution to zero-offset VSP data

The aim of designing deconvolution operators is to extract the reflectivity series from seismic sections. Due to the noise, source signature inconsistency, reflection/transmission, anelastic attenuation, and multiples, the amplitude of a propagating seismic wave varies as a function of time. Because of these factors the frequency spectra of seismic signals narrow with time. Recognition of reflectors using upgoing waves is one of the notable properties of vertical seismic profiling (VSP) data. Designing a deconvolution operator for VSP data based on downgoing waves is considered to be one of the most ideal deconvolution methods intended to produce high-resolution images in routine processing of zero-offset VSP data. For such an analysis, the Gabor deconvolution operator has been designed using the downgoing wavefield and then was applied to the upgoing wavefield, and hyperbolic smoothing was used to estimate the wavelet. The final result of applying the deconvolution operator is a VSP section with superior resolution. To compare this method with customary methods of deconvolution, the Wiener deconvolution was applied to the synthetic and real data, and the results were compared with those of the Gabor deconvolution.

Estimation of azimuthal anisotropy from VSP data using multicomponent S-wave velocity analysis

Observation of azimuthal shear wave anisotropy can be useful for characterization of fractures or stress fields. Shear wave anisotropy is often estimated by measuring splitting of individual shear wave events in vertical seismic profile (VSP) data. However, this method may become unreliable for zero-offset (marine) VSP where the seismogram often contains no strong individual shear events, such as direct downgoing shear wave, but often contains many low-amplitude PS mode converted waves. We have developed a new approach for estimation of the fast and slow shear wave velocities and orientation of polarization planes based on the multicomponent linear traveltime moveout velocity analysis. This technique is applicable to zero-offset VSP data, and should take advantage of the presence of a large number of shear wave events with the same apparent velocity (which, for a horizontally layered medium, should be close to the interval velocity). The approach assumes that the VSP data are acquired in a vertical well drilled in an orthorhombic medium with a horizontal symmetry plane (including horizontal transverse isotropy). The main idea is to estimate the dominant apparent velocity for a given polarization direction by measuring the coherency of the seismic signal of a large number of events as a function of the apparent velocity. The algorithm was tested on marine three-component (3C) VSP acquired in the North West Shelf of Australia, and on land 3C VSP acquired with different sources in the same borehole located in Otway Basin, Victoria. These tests show good agreement between anisotropy parameters (magnitude and orientation) derived from the VSP and cross-dipole sonic log data.

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.

Pure S-waves in land P-wave source VSP data

Conventional land vertical seismic profiling (VSP) exploration usually uses P-wave sources and three-component geophones for receivers, emphasizing P-and converted S-waves. Previous studies show that both dynamite borehole shots and vertical vibrations from controllable seismic sources at the surface will produce relatively strong pure P-waves and weaker pure S-waves. Interfaces with a large Poisson’s ratio difference have a positive influence on the formation of strong transmitted converted S-waves. By a comparative analysis of pure S-waves from sources and converted downgoing S-waves, we believe that the main frequency of pure S-waves is usually lower than pure P-waves while the main frequency of downgoing converted S-waves is close to that of P-waves. We have studied zero-offset and offset VSP data from land P-wave sources. Results show that pure S-waves commonly exist in these data with differences in wave intensity. S-wave velocity can be obtained from the P-wave source zero-offset VSP data. Finally, we discuss the bright future of joint application of VSP P-and S-waves and the full use of S-waves in P-wave source VSP data.

CDP mapping and image reconstruction by using offset VSP data

Because zero-offset VSP (Vertical Seismic Profile) data can only provide the information of rock properties and structure in the area around the Fresnel zone within the well, the scheme of VSP with offset was developed to acquire the reflection information away from the borehole in order to widen the range of VSP survey and to improve the precision of imaging.