Physical constraints on c13 and δ for transversely isotropic hydrocarbon source rocks

Based on the theory of anisotropic elasticity and observation of static mechanic measurement of transversely isotropic hydrocarbon source rocks or rock‐like materials, we reasoned that one of the three principal Poisson's ratios of transversely isotropic hydrocarbon source rocks should always be greater than the other two and they should be generally positive. From these relations, we derived tight physical constraints on c₁₃, Thomsen parameter δ, and anellipticity parameter η. Some of the published data from laboratory velocity anisotropy measurement are lying outside of the constraints. We analysed that they are primarily caused by substantial uncertainty associated with the oblique velocity measurement. These physical constraints will be useful for our understanding of Thomsen parameter δ, data quality checking, and predicting δ from measurements perpendicular and parallel to the symmetrical axis of transversely isotropic medium. The physical constraints should also have potential application in anisotropic seismic data processing.     

Elastic constants and velocity surfaces of indurated anisotropic shales

The velocities of two Devonian-Mississippian shales have been measured to confining pressures of 200 MPa in a laboratory study of anisotropy and wave propagation. Both samples were found to be transversely isotropic at elevated pressures with the main symmetry axis perpendicular to bedding. The elastic constants of the shales were used to calculate phase and group velocity surfaces as a function of angle to the bedding normal. Multiple velocity measurements in non-symmetry directions, not undertaken in previously published studies of shales, have been used to confirm features observed on calculated velocity surfaces. It is demonstrated that velocities measured in non-symmetry directions are phase velocities. Group velocities were found to be significantly lower than the corresponding phase velocities of the shales due to their high anisotropies. Shear wave splitting was found to be negligible for propagation directions within approximately 30° of the bedding normals.     

Seismic anisotropy of shales

Shales are a major component of sedimentary basins, and they play a decisive role in fluid flow and seismic‐wave propagation because of their low permeability and anisotropic microstructure. Shale anisotropy needs to be quantified to obtain reliable information on reservoir fluid, lithology and pore pressure from seismic data, and to understand time‐to‐depth conversion errors and non‐hyperbolic moveout. A single anisotropy parameter, Thomsen's δ parameter, is sufficient to explain the difference between the small‐offset normal‐moveout velocity and vertical velocity, and to interpret the small‐offset AVO response. The sign of this parameter is poorly understood, with both positive and negative values having been reported in the literature. δ is sensitive to the compliance of the contact regions between clay particles and to the degree of disorder in the orientation of clay particles. If the ratio of the normal to shear compliance of the contact regions exceeds a critical value, the presence of these regions acts to increase δ, and a change in the sign of δ, from the negative values characteristic of clay minerals to the positive values commonly reported for shales, may occur. Misalignment of the clay particles can also lead to a positive value of δ. For transverse isotropy, the elastic anisotropy parameters can be written in terms of the coefficients W₂₀₀ and W₄₀₀ in an expansion of the clay‐particle orientation distribution function in generalized Legendre functions. For a given value of W₂₀₀, decreasing W₄₀₀ leads to an increase in δ, while for fixed W₄₀₀, δ increases with increasing W₂₀₀. Perfect alignment of clay particles with normals along the symmetry axis corresponds to the maximum values of W₂₀₀ and W₄₀₀, given by and . A comparison of the predictions of the theory with laboratory measurements shows that most shales lie in a region of the (W₂₀₀, W₄₀₀)‐plane defined by W₄₀₀/W₂₀₀≤W^max₄₀₀/W^max₂₀₀ .     

Velocities of compressional and shear waves in limestones

Carbonate rocks are important hydrocarbon reservoir rocks with complex textures and petrophysical properties (porosity and permeability) mainly resulting from various diagenetic processes (compaction, dissolution, precipitation, cementation, etc.). These complexities make prediction of reservoir characteristics (e.g. porosity and permeability) from their seismic properties very difficult. To explore the relationship between the seismic, petrophysical and geological properties, ultrasonic compressional‐ and shear‐wave velocity measurements were made under a simulated in situ condition of pressure (50 MPa hydrostatic effective pressure) at frequencies of approximately 0.85 MHz and 0.7 MHz, respectively, using a pulse‐echo method. The measurements were made both in vacuum‐dry and fully saturated conditions in oolitic limestones of the Great Oolite Formation of southern England. Some of the rocks were fully saturated with oil. The acoustic measurements were supplemented by porosity and permeability measurements, petrological and pore geometry studies of resin‐impregnated polished thin sections, X‐ray diffraction analyses and scanning electron microscope studies to investigate submicroscopic textures and micropores. It is shown that the compressional‐ and shear‐wave velocities (V_p and V_s, respectively) decrease with increasing porosity and that V_p decreases approximately twice as fast as V_s. The systematic differences in pore structures (e.g. the aspect ratio) of the limestones produce large residuals in the velocity versus porosity relationship. It is demonstrated that the velocity versus porosity relationship can be improved by removing the pore‐structure‐dependent variations from the residuals. The introduction of water into the pore space decreases the shear moduli of the rocks by about 2 GPa, suggesting that there exists a fluid/matrix interaction at grain contacts, which reduces the rigidity. The predicted Biot–Gassmann velocity values are greater than the measured velocity values due to the rock–fluid interaction. This is not accounted for in the Biot–Gassmann velocity models and velocity dispersion due to a local flow mechanism. The velocities predicted by the Raymer and time‐average relationships overestimated the measured velocities even more than the Biot model.     

Ray parameters of diffracted long period P and S waves and the velocities at the base of the mantle

The derivation of P and S velocities at the core-mantle boundary (CMB) from long-period diffracted waves by the use of the simple ray-theoretical formulav _CMB=r _c /p (v _CMB=velocity at the CMB;r _c =core radius;p=ray parameter) yields apparent velocity values which differ from the true velocities. Using a dominant period of about 20 sec for calculating theoretical seismograms, we found a linear relation between the apparent velocity and the average velocity in a transition zone at the base of the mantle with fixed velocity on top.The ray parameters determined from long-period earthquake data are found to be 4.540±0.035 and 8.427±0.072 sec/deg for P_diff and S_diff, respectively. These values yield apparent velocities of 13.378±0.103 for P and 7.207±0.062 km/sec for S waves. By means of the theoretical relation between apparent and average velocity and under the assumption of linear variation of velocity with depth, one can invert the apparent velocities into true CMB velocities of 13.736±0.170 and 7.320±0.124 km/sec. These results imply positive velocity gradients at the base of the mantle and hence no significant departures from adiabaticity and homogeneity.Contribution No. 211 of the Geophysical Institute, University of Karlsruhe.     

Stress Sensitivity of Seismic and Electric Rock Properties of the Upper Continental Crust at the KTB

We test the hypothesis that the general trend of P-wave and S-wave sonic log velocities and resistivity with depth in the pilot hole of the KTB site Germany, can be explained by the progressive closure of the compliant porosity with increasingly effective pressure. We introduce a quantity θ_c characterizing the stress sensitivity of the mentioned properties. An analysis of the downhole measurements showed that estimates of the quantitiy θ_c for seismic velocities and electrical formation factor of the in situ formation coincide. Moreover, this quantity is 3.5 to 4.5 times larger than the averaged stress sensitivity obtained from core samples. We conclude that the hypothesis mentioned above is consistent with both data sets. Moreover, since θ_c corresponds approximately to the inverse of the effective crack aspect ratio, larger in situ estimates of θ_c might reflect the influence of fractures and faults on the stress sensitivity of the crystalline formation in contrast to the stress sensitivity of the nearly intact core samples. Finally, because the stress sensitivity is directly related to the elastic nonlinearity we conclude that the elastic nonlinearity (i.e., deviation from linear stress-strain relationship i.e., Hooke's law) of the KTB rocks is significantly larger in situ than in the laboratory.     

Determination of shale stiffness tensor from standard logs

A technique allowing inversion of the shale stiffness tensor from standard logging data: sonic velocities, density, porosity and clay content is developed. The inversion is based on the effective medium theory. The testing of the technique on laboratory measurements of the elastic wave velocities in shale samples shows that the inversion makes it possible to predict the elastic wave velocities V_P, V_S1 and V_S2 in any direction within an error of a few per cent. The technique has been applied for the stiffness tensor inversion along a well penetrating a shale formation of the Mississippian age altered by thin layers of limestone. It is demonstrated that the symmetry of a stiffness tensor inverted at the sonic frequency (2 kHz) is slightly orthorhombic and taking into account the experimental errors, can be related to the vertical transverse isotropy symmetry. For the productive interval of the shale formation, the Thomsen parameters ?, γ, and δ average, respectively, 0.32, 0.25 and 0.21, which indicate anelliptic behaviour of the velocities in this shale. The coefficients of anisotropy of this shale interval are around 24% and 20% for the compressional and shear waves, respectively. The values of the inverted velocities in the bedding plane for this interval are in good agreement with the laboratory measurements. The technique also allows inversion of the water saturation of the formation (Sw) and the inverted values are in agreement with the Sw values available for this formation. A Backus‐like upscaling of the inverted stiffness tensors is carried out for the lower and upper bounds of the frequency band used in the crosswell tomography (100 Hz and 500 Hz). These results can serve as an initial velocity model for the microearthquake location during hydrofracking of the shale formation.     

Study of P-wave velocities and attenuation coefficients of Gondwana rocks from Chanda-Wardha valley coalfield, Maharashtra, India

This paper describes the findings of the study pertaining to the laboratory measurements of longitudinal wave velocities and attenuation coefficients of various Gondwana rocks of Chikhalgaon, Saoner and Agarjhari areas of Chanda-Wardha valley coalfield. It is found that Barakar sandstones, in general, have higher longitudinal wave velocities than Barakar and Talchir shales and Kamthi sandstones. Of the Barakar sandstones, the fine grained feldspathised variety has the maximum velocity. Attenuation coefficients of coarse-grained rocks are higher than those of fine grained ones. Black carbonaceous shales of Barakar are characterised by moderately high longitudinal wave velocities and attenuation coefficients. Coals are characterized by low longitudinal wave velocities and high attenuation coefficients. Longitudinal wave velocities of the rocks along the bedding plane are always higher than those perpendicular to the bedding plane.     

Converted-wave imaging in anisotropic media: theory and case studies

Common‐conversion‐point binning associated with converted‐wave (C‐wave) processing complicates the task of parameter estimation, especially in anisotropic media. To overcome this problem, we derive new expressions for converted‐wave prestack time migration (PSTM) in anisotropic media and illustrate their applications using both 2D and 3D data examples. The converted‐wave kinematic response in inhomogeneous media with vertical transverse isotropy is separated into two parts: the response in horizontally layered vertical transverse isotrophy media and the response from a point‐scatterer. The former controls the stacking process and the latter controls the process of PSTM. The C‐wave traveltime in horizontally layered vertical transverse isotrophy media is determined by four parameters: the C‐wave stacking velocity V_C2, the vertical and effective velocity ratios γ₀ and γ_eff, and the C‐wave anisotropic parameter χ_eff. These four parameters are referred to as the C‐wave stacking velocity model. In contrast, the C‐wave diffraction time from a point‐scatterer is determined by five parameters: γ₀, V_P2, V_S2, η_eff and ζ_eff, where η_eff and ζ_eff are, respectively, the P‐ and S‐wave anisotropic parameters, and V_P2 and V_S2 are the corresponding stacking velocities. V_P2, V_S2, η_eff and ζ_eff are referred to as the C‐wave PSTM velocity model. There is a one‐to‐one analytical link between the stacking velocity model and the PSTM velocity model. There is also a simple analytical link between the C‐wave stacking velocities V_C2 and the migration velocity V_Cmig, which is in turn linked to V_P2 and V_S2. Based on the above, we have developed an interactive processing scheme to build the stacking and PSTM velocity models and to perform 2D and 3D C‐wave anisotropic PSTM. Real data applications show that the PSTM scheme substantially improves the quality of C‐wave imaging compared with the dip‐moveout scheme, and these improvements have been confirmed by drilling.     

Influence of subsurface injection on time‐lapse seismic: laboratory studies at seismic and ultrasonic frequencies

Seismic monitoring of reservoir and overburden performance during subsurface CO₂ storage plays a key role in ensuring efficiency and safety. Proper interpretation of monitoring data requires knowledge about the rock physical phenomena occurring in the subsurface formations. This work focuses on rock stiffness and elastic velocity changes of a shale overburden formation caused by both reservoir inflation induced stress changes and leakage of CO₂ into the overburden. In laboratory experiments, Pierre shale I core plugs were loaded along the stress path representative for the in situ stress changes experienced by caprock during reservoir inflation. Tests were carried out in a triaxial compaction cell combining three measurement techniques and permitting for determination of (i) ultrasonic velocities, (ii) quasistatic rock deformations, and (iii) dynamic elastic stiffness at seismic frequencies within a single test, which allowed to quantify effects of seismic dispersion. In addition, fluid substitution effects connected with possible CO₂ leakage into the caprock formation were modelled by the modified anisotropic Gassmann model. Results of this work indicate that (i) stress sensitivity of Pierre shale I is frequency dependent; (ii) reservoir inflation leads to the increase of the overburden Young's modulus and Poisson's ratio; (iii) in situ stress changes mostly affect the P‐wave velocities; (iv) small leakage of the CO₂ into the overburden may lead to the velocity changes, which are comparable with one associated with geomechanical influence; (v) non‐elastic effects increase stress sensitivity of an acoustic waves; (iv) and both geomechanical and fluid substitution effects would create significant time shifts, which should be detectable by time‐lapse seismic.     

Effect of sub‐core scale heterogeneities on acoustic and electrical properties of a reservoir rock: a CO2 flooding experiment of brine saturated sandstone in a computed tomography scanner

The effect of sub‐core scale heterogeneity on fluid distribution pattern, and the electrical and acoustic properties of a typical reservoir rock was studied by performing drainage and imbibition flooding tests with CO₂ and brine in a laboratory. Moderately layered Rothbach sandstone was used as a test specimen. Two core samples were drilled; one perpendicular and the other parallel to the layering to allow injection of fluids along and normal to the bedding plane. During the test 3D images of fluid distribution and saturation levels were mapped by an industrial X‐ray CT‐scanner together with simultaneous measurement of electrical resistivity, ultrasonic velocities as well as amplitudes. The results showed how the layering and the flooding direction influenced the fluid distribution pattern and the saturation level of the fluids. For a given fluid saturation level, the measured changes in the acoustic and electrical parameters were affected by both the fluid distribution pattern and the layering orientation relative to the measurement direction. The P‐wave amplitude and the electrical resistivity were more sensitive to small changes in the fluid distribution patterns than the P‐wave velocity. The change in amplitude was the most affected by the orientation of the layering and the resulting fluid distribution patterns. In some instances the change due to the fluid distribution pattern was higher than the variation caused by the change in CO₂ saturation. As a result the Gassmann relation based on ‘uniform' or ‘patchy' saturation pattern was not suitable to predict the P‐wave velocity variation. Overall, the results demonstrate the importance of core‐imaging to improve our understanding of fluid distribution patterns and the associated effects on measured rock‐physics properties.     

Dispersion and radial depth of investigation of borehole modes

Sonic techniques in geophysical prospecting involve elastic wave velocity measurements that are performed by placing acoustic transmitters and receivers in a fluid‐filled borehole. The signals recorded at the receivers are processed to obtain compressional‐ and shear‐wave velocities in the surrounding formation. These velocities are generally used in seismic surveys for the time‐to‐depth conversion and other formation parameters, such as porosity and lithology. Depending upon the type of transmitter used (e.g. monopole or dipole) and as a result of eccentering, it is possible to excite axisymmetric (n= 0) , flexural (n= 1) and quadrupole (n= 2) families of modes propagating along the borehole. We present a study of various propagating and leaky modes that includes their dispersion and attenuation characteristics caused by radiation into the surrounding formation. A knowledge of propagation characteristics of borehole modes helps in a proper selection of transmitter bandwidth for suppressing unwanted modes that create problems in the inversion for the compressional‐ and shear‐wave velocities from the dispersive arrivals. It also helps in the design of a transmitter for a preferential excitation of a given mode in order to reduce interference with drill‐collar or drilling noise for sonic measurements‐while‐drilling. Computational results for the axisymmetric family of modes in a fast formation with a shear‐wave velocity of 2032 m/s show the existence of Stoneley, pseudo‐Rayleigh and anharmonic cut‐off modes. In a slow formation with a shear‐wave velocity of 508 m/s, we find the existence of the Stoneley mode and the first leaky compressional mode which cuts in at approximately the same normalized frequency ωa/V_S= 2.5 (a is the borehole radius) as that of the fast formation. The corresponding modes among the flexural family include the lowest‐order flexural and anharmonic cut‐off modes. For both the fast and slow formations, the first anharmonic mode cuts in at a normalized frequency ωa/V_S= 1.5 approximately. Cut‐off frequencies of anharmonic modes are inversely proportional to the borehole radius in the absence of any tool. The borehole quadrupole mode can also be used for estimating formation shear slownesses. The radial depth of investigation with a quadrupole mode is marginally less than that of a flexural mode because of its higher frequency of excitation.     

Measuring Concentrations of Dissolved Methane and Ethane and the 13C of Methane in Shale and Till

Baseline characterization of concentrations and isotopic values of dissolved natural gases is needed to identify contamination caused by the leakage of fugitive gases from oil and gas activities. Methods to collect and analyze baseline concentration‐depth profiles of dissolved CH₄ and C₂H₆ and δ¹³C‐CH₄ in shales and Quaternary clayey tills were assessed at two sites in the Williston Basin, Canada. Core and cuttings samples were stored in Isojars^® in a low O₂ headspace prior to analysis. Measurements and multiphase diffusion modeling show that the gas concentrations in core samples yield well‐defined and reproducible depth profiles after 31‐d equilibration. No measurable oxidative loss or production during core sample storage was observed. Concentrations from cuttings and mud gas logging (including IsoTubes^®) were much lower than from cores, but correlated well. Simulations suggest the lower concentrations from cuttings can be attributed to drilling time, and therefore their use to define gas concentration profiles may have inherent limitations. Calculations based on mud gas logging show the method can provide estimates of core concentrations if operational parameters for the mud gas capture cylinder are quantified. The δ¹³C‐CH₄ measured from mud gas, IsoTubes^®, cuttings, and core samples are consistent, exhibiting slight variations that should not alter the implications of the results in identifying the sources of the gases. This study shows core and mud gas techniques and, to a lesser extent, cuttings, can generate high‐resolution depth profiles of dissolved hydrocarbon gas concentrations and their isotopes.     

Ray tomography based on azimuthal anomalies

A method of estimating the lateral velocity variations in the 2D case using the data on deviations of wave paths from straight lines (or great circle paths in the spherical case) is proposed. The method is designed for interpretation of azimuthal anomalies of surface waves which contain information on lateral variations of phase velocities supplementary to that obtained from travel-time data in traditional surface wave tomography. In the particular 2D case, when the starting velocity is constant (c ₀) and velocity perturbations δc(x,y) are sufficiently smooth, a relationship between azimuthal anomaly δα and velocity perturbations δc(x,y) can be obtained by approximate integration of the ray tracing system, which leads to the following functional: $$\delta \alpha = \int_0^L {\frac{{s(\nabla m,n_0 )}}{L}} ds,$$ wherem(x,y)=δc(x,y)/c ₀,L is the length of the ray,n ₀ is a unit vector perpendicular to the ray in the starting model, integration being performed from the source to the receiver. This formula is valid for both plane and spherical cases. Numerical testing proves that for a velocity perturbation which does not exceed 10%, this approximation is fairly good. Lateral variations of surface wave velocities satisfy these assumptions. Therefore this functional may be used in surface wave tomography. For the determination ofm(x,y) from a set ofδα _k corresponding to different wave paths, the solution is represented as a series in basis functions, which are constructed using the criterion of smoothness of the solution proposed byTarantola andNersessian (1984) for time-delay tomography problems. Numerical testing demonstrates the efficiency of the tomography method. The method is applied to the reconstruction of lateral variations of Rayleigh wave phase velocities in the Carpathian-Balkan region. The variations of phase velocities obtained from data on azimuthal anomalies are found to be correlated with group-velocity variations obtained from travel-time data.     

Improved understanding of velocity–saturation relationships using 4D computer-tomography acoustic measurements

A recently developed laboratory method allows for simultaneous imaging of fluid distribution and measurements of acoustic‐wave velocities during flooding experiments. Using a specially developed acoustic sample holder that combines high pressure capacity with good transparency for X‐rays, it becomes possible to investigate relationships between velocity and fluid saturation at reservoir stress levels. High‐resolution 3D images can be constructed from thin slices of cross‐sectional computer‐tomography scans (CT scans) covering the entire rock‐core volume, and from imaging the distribution of fluid at different saturation levels. The X‐ray imaging clearly adds a new dimension to rock‐physics measurements; it can be used in the explanation of variations in measured velocities from core‐scale heterogeneities. Computer tomography gives a detailed visualization of density regimes in reservoir rocks within a core. This allows an examination of the interior of core samples, revealing inhomogeneities, porosity and fluid distribution. This mapping will not only lead to an explanation of acoustic‐velocity measurements; it may also contribute to an increased understanding of the fluid‐flow process and gas/liquid mixing mechanisms in rock. Immiscible and miscible flow in core plugs can be mapped simultaneously with acoustic measurements. The effects of core heterogeneity and experimentally introduced effects can be separated, to clarify the validity of measured velocity relationships.     

Acoustic and petrophysical relationships in low-shale sandstone reservoir rocks

This paper describes the measurements of the acoustic and petrophysical properties of two suites of low‐shale sandstone samples from North Sea hydrocarbon reservoirs, under simulated reservoir conditions. The acoustic velocities and quality factors of the samples, saturated with different pore fluids (brine, dead oil and kerosene), were measured at a frequency of about 0.8 MHz and over a range of pressures from 5 MPa to 40 MPa. The compressional‐wave velocity is strongly correlated with the shear‐wave velocity in this suite of rocks. The ratio V_P/V_S varies significantly with change of both pore‐fluid type and differential pressure, confirming the usefulness of this parameter for seismic monitoring of producing reservoirs. The results of quality factor measurements were compared with predictions from Biot‐flow and squirt‐flow loss mechanisms. The results suggested that the dominating loss in these samples is due to squirt‐flow of fluid between the pores of various geometries. The contribution of the Biot‐flow loss mechanism to the total loss is negligible. The compressional‐wave quality factor was shown to be inversely correlated with rock permeability, suggesting the possibility of using attenuation as a permeability indicator tool in low‐shale, high‐porosity sandstone reservoirs.     

A multi‐azimuth seismic refraction study for a horizontal transverse isotropic medium: physical modelling results

To investigate the characteristics of the anisotropic stratum, a multi‐azimuth seismic refraction technique is proposed in this study since the travel time anomaly of the refraction wave induced by this anisotropic stratum will be large for a far offset receiver. To simplify the problem, a two‐layer (isotropy–horizontal transverse isotropy) model is considered. A new travel time equation of the refracted P‐wave propagation in this two‐layer model is derived, which is the function of the phase and group velocities of the horizontal transverse isotropic stratum. In addition, the measured refraction wave velocity in the physical model experiment is the group velocity. The isotropic intercept time equation of a refraction wave can be directly used to estimate the thickness of the top (isotropic) layer of the two‐layer model because the contrast between the phase and group velocities of the horizontal transverse isotropic medium is seldom greater than 10% in the Earth. If the contrast between the phase and group velocities of an anisotropic medium is small, the approximated travel time equation of a refraction wave is obtained. This equation is only dependent on the group velocity of the horizontal transverse isotropic stratum. The elastic constants A₁₁, A₁₃, and A₃₃ and the Thomsen anisotropic parameter ε of the horizontal transverse isotropic stratum can be estimated using this multi‐azimuth seismic refraction technique. Furthermore, under a condition of weak anisotropy, the Thomsen anisotropic parameter δ of the horizontal transverse isotropic stratum can be estimated by this technique as well.     

The estimation of shear-wave statics using in situ measurements in marine near-surface sediments

Shear‐wave statics in marine seismic exploration data are routinely too large to be estimated using conventional techniques. Near‐surface unconsolidated sediments are often characterized by low values of V_s and steep velocity gradients. Minor variations in sediment properties at these depths correspond to variations in the shear‐wave velocity and will produce significant static shifts. It is suggested that a significant proportion of the shear‐wave statics solution can be estimated by performing a separate high‐resolution survey to target near‐surface unconsolidated sediments. Love‐wave, shear‐wave refraction and geotechnical measurements were individually used to form high‐resolution near‐surface shear‐wave velocity models to estimate the shear‐wave statics for a designated survey line. Comparisons with predicted statics revealed that shear‐wave statics could not be estimated using a velocity model predicted by substituting geotechnical measurements into empirical relationships. Empirical relationships represent a vast simplification of the factors that control V_s and are therefore not sufficiently sensitive to estimate shear‐wave statics. Refraction measurements are potentially sensitive to short‐wavelength variations in sediment properties when combined with accurate navigational data. Statics estimated from Love‐wave data are less sensitive, and sometimes smoothed in appearance, since interpreted velocity values represent an average both laterally and vertically over the receiver array and the frequency–depth sensitivity range, respectively. For the survey site, statics estimated from near‐surface irregularities using shear‐wave refraction measurements represent almost half the total statics solution. More often, this proportion will be greater when bedrock relief is less.     

P‐wave stacking‐velocity tomography for VTI media

A major complication caused by anisotropy in velocity analysis and imaging is the uncertainty in estimating the vertical velocity and depth scale of the model from surface data. For laterally homogeneous VTI (transversely isotropic with a vertical symmetry axis) media above the target reflector, P‐wave moveout has to be combined with other information (e.g. borehole data or converted waves) to build velocity models for depth imaging. The presence of lateral heterogeneity in the overburden creates the dependence of P‐wave reflection data on all three relevant parameters (the vertical velocity V_P0 and the Thomsen coefficients ε and δ) and, therefore, may help to determine the depth scale of the velocity field. Here, we propose a tomographic algorithm designed to invert NMO ellipses (obtained from azimuthally varying stacking velocities) and zero‐offset traveltimes of P‐waves for the parameters of homogeneous VTI layers separated by either plane dipping or curved interfaces. For plane non‐intersecting layer boundaries, the interval parameters cannot be recovered from P‐wave moveout in a unique way. Nonetheless, if the reflectors have sufficiently different azimuths, a priori knowledge of any single interval parameter makes it possible to reconstruct the whole model in depth. For example, the parameter estimation becomes unique if the subsurface layer is known to be isotropic. In the case of 2D inversion on the dip line of co‐orientated reflectors, it is necessary to specify one parameter (e.g. the vertical velocity) per layer. Despite the higher complexity of models with curved interfaces, the increased angle coverage of reflected rays helps to resolve the trade‐offs between the medium parameters. Singular value decomposition (SVD) shows that in the presence of sufficient interface curvature all parameters needed for anisotropic depth processing can be obtained solely from conventional‐spread P‐wave moveout. By performing tests on noise‐contaminated data we demonstrate that the tomographic inversion procedure reconstructs both the interfaces and the VTI parameters with high accuracy. Both SVD analysis and moveout inversion are implemented using an efficient modelling technique based on the theory of NMO‐velocity surfaces generalized for wave propagation through curved interfaces.