Horizontal Transverse Isotropy Research Articles

Horizontal Transverse Isotropy Studied Using Tools for Full-Azimuth Seismic Data Processing and an Advanced Well Logging Complex on the Example of Famennian Deposits of the Yugomashevskoye Field

Horizontal Transverse Isotropy Studied Using Tools for Full-Azimuth Seismic Data Processing and an Advanced Well Logging Complex on the Example of Famennian Deposits of the Yugomashevskoye Field

Integration of deep-learning fault segmentation, horizontal transverse isotropy analysis, and ambient microseismic methods to enhance fracture prediction in the Crisol Anticline, Colombia

The analysis of fault and fracture systems in the subsurface is crucial for identifying potential reservoirs and optimizing production. However, conventional fault interpretation methods have limitations due to the complexity and amount of data involved. In this study, a multimethod approach was used to analyze fault and fracture systems in the Crisol area of the Valley Middle Magdalena basin. We used deep-learning fault segmentation, horizontal transverse isotropy (HTI), and ambient microseismic methods to identify and characterize fault and fracture systems in the study area. The deep-learning fault segmentation method helped to identify complex fault systems, whereas the HTI method identified areas and orientations of intense fracturing that occurred at any prior period of stress in geologic time. Meanwhile, the ambient microseismic method measured active rock movements and fracturing in the subsurface that occurred during the microseismic trace recording. The application of multiple methods for analyzing fault and fracture systems in the subsurface is demonstrated to offer a more comprehensive understanding of the geology and enhance the accuracy of well placement and production forecasts.

Inversion of fracture weakness parameters based on 3C vertical seismic profile data — Part I: Horizontal transversely isotropic media composed of a single fracture set in the isotropic background media

Natural fractures in oil and gas reservoirs are a crucial factor that cannot be ignored because they significantly influence the reservoir’s petrophysical properties and hydrocarbon development. A horizontal transversely isotropic (HTI) medium composed of a single fracture set in an isotropic background is a typical anisotropic medium. Meanwhile, the S-wave splitting is a sensitive response of such anisotropic media, resulting in the generation of fast and slow S waves. The normal and tangential fracture weaknesses are crucial parameters that characterize the anisotropy of fractured media. We develop an inversion method for fracture weakness based on 3C vertical seismic profiling (3CVSP) data. First, assuming weak anisotropy and an HTI medium containing a single fracture set, we derive a first-order linear approximation of the traveltimes of the converted fast and slow S waves (PS1 and PS2 waves) with respect to fracture weakness parameters in the phase velocity domain. By solving for the horizontal projection of the slowness vector, approximate equations of the traveltimes of the PS1 and PS2 waves are converted from the phase velocity domain to the group velocity domain. Furthermore, we devise an inversion workflow consisting of three primary steps: (1) preprocessing the VSP data to derive the traveltimes and azimuth of the HTI medium, (2) constructing a forward model with undetermined fracture weakness parameters, and (3) following the establishment of the objective function, conducting the inversion for the fracture weakness parameters. We demonstrate the reliability of the method through numerical examples and synthetic 3CVSP data. The inversion errors are primarily influenced by the azimuth angle, with minimal influence from the receiver depth. Furthermore, a collective set of inverted results derived from all geophones is more stable and accurate than individual geophones. The application to actual 3CVSP data further confirms the effectiveness of our approach.

Azimuth anisotropy prediction and correction of wide-azimuth seismic data

For seismic wave propagation in media with horizontal transverse isotropy (HTI), kinematic and dynamic attributes are anisotropic. P waves propagate slower in perpendicular to fracture azimuth than parallel to it, whereas reflection strength and frequency vary with azimuth. The azimuthal effects on reflection coefficients and seismic wave velocities in an HTI medium are quantitatively analyzed. The resulting theory-based and real-world azimuth gathers demonstrate the anisotropic nature of such media. The fitting of the ellipse is used to quantitatively predict the direction and strength of anisotropy in the study area, which is consistent with that obtained by the S-wave splitting prediction method. In wide-azimuth data processing, measures are taken to eliminate the influence of azimuthal anisotropy, and the coherent spectrum pickup method is used to accurately calculate the azimuthal velocity of underground HTI media and perform azimuthal anisotropy correction processing, which eliminates the time difference between fast and slow wave caused by azimuthal anisotropy. The achieved results provide support for subsequent high-resolution imaging.

Horizontal transverse isotropy anisotropic parameter inversion via azimuthal seismic velocity anisotropy and its application to anisotropic 3D in-situ stress estimation

Anisotropic parameter inversion in horizontal transverse isotropy (HTI) media plays an important role in predicting the fracture density and the anisotropic in-situ stress for unconventional reservoirs. The current industry practice is to use the azimuthal PP-wave reflection coefficient to estimate the HTI anisotropic parameters. Based on the linear slip theory, we develop an innovative approach that uses azimuthal P-wave phase velocity to calculate HTI anisotropic parameters, which presents superiority over the conventional azimuthal PP-wave reflection coefficient inversion. Specifically, we first verify that the azimuthal P-wave phase velocity is for the HTI elliptical fitting than the azimuthal PP-wave reflection coefficient using the analytical formulations. Second, we sort the prestack wide-azimuth data into offset vector tile sectors and perform amplitude-variation-with-offset inversion at each azimuth. Third, we apply an elliptical fitting to the obtained azimuthal P-wave phase velocities to estimate the HTI anisotropic parameters, fracture density, and fracture direction. Fourth, based on the HTI mechanical earth model, we formulate a cost-effective 3D in-situ stress estimation method using the obtained elastic parameters and fracture compliance. Finally, field examples from the Zhaotong area, China, demonstrate that the estimated fracture density and anisotropic in-situ stress are more accurate and have higher resolution compared with conventional methods. The dominant stress regime in the study area is a strike-slip faulting regime with a governing orientation of northeast–southwest and presents good alignments with well logs, which demonstrates the reliability and accuracy of our method for predicting fracture density and anisotropic in-situ stress.

In situ stress prediction method for decoupled overburden pressure under tectonic constraints

Abstract The prediction of in situ stress based on azimuthal seismic data has extensive use in horizon crushability evaluation. Nonetheless, existing in situ stress seismic prediction models do not consider overburden pressure and tectonic strain, which limit the prediction accuracy. To this end, we propose a decoupled overburden pressure in situ stress prediction method under tectonic constraints. The key to this method is to consider that the overburden pressure could act on the rock skeleton and pore fluid, i.e. generating effective pressure and pore pressure; the pore pressure can be estimated using Eaton's method, and then the effective stress can be obtained. The relationship between tectonic strain and effective pressure is constructed based on Hooke's law, where tectonic strain can be calculated from curvature attributes extracted from seismic data. Introducing pore pressure and deriving a model for calculating the maximum and minimum horizontal stresses and the difference in horizontal stress ratio for orthotropic media (OA). When the Thomson anisotropy parameters and the pore pressure are neglected, the proposed model can be degraded to a conventional horizontal transverse isotropy medium in situ stress prediction model, which proves the validity of the model. The results of sensitivity analysis experiments affirm the need to decouple overburden pressure and account for tectonic strain when predicting in situ stress reasonably. Finally, single-well and azimuthal seismic prediction were carried out by using the a priori information from well logging and seismic data.

Azimuthal Prestack Seismic Anisotropic Inversion on a Deep and Tight Carbonate Reservoir From the North Potwar Basin of Pakistan

Summary Quantitative characterization of deep, tight, and heterogeneous reservoirs plays an important role in identifying hydrocarbon pathways for effective and optimal reservoir field development. In this case study, we used an azimuthal prestack seismic anisotropic inversion approach to estimate attributes of horizontal transverse isotropy (HTI) caused by a set of vertical fractures, oriented cracks, and stress. Anisotropic inversion facilitated the conversion of interface properties to the corresponding layer-based properties, which led to the quantitative interpretation of reservoir properties related to azimuthal variation in seismic amplitudes. To estimate the anisotropy magnitude and the direction of the isotropy axis in HTI media, elastic properties (P-impedance and Vp/Vs) obtained from prestack seismic inversion (using six azimuth × four angle stack) served as inputs. The isotropic low-frequency model (LFM) is used as the foundation of the inversion for all azimuths, and the anisotropy effects are later added by updating the model along the azimuths. The direction of the isotropy plane resulting from the anisotropic inversion is determined by using the maximum horizontal stress as a prior constraint, which eliminates any inherent uncertainty. The workflow used effectively characterized the orientation and density of fractures from the recently discovered oilfield reservoirs of the Paleocene (Lockhart) formation located in Pakistan’s north Potwar Basin. It also helped improve the prediction accuracy for fractures in the study area. According to the observations (fractures) from the exploratory drilled well (D1) in the tight carbonate (Lockhart) reservoir, a significant amount of anisotropy magnitude is observed. This provides the basis for hydrocarbon exploration, field development, and reliable drilling decisions.

In situ stress determination in isotropic and anisotropic rocks and its application to a naturally fractured reservoir

Anisotropies exist in many sedimentary rocks, particularly in naturally fractured reservoirs, causing horizontal stress anisotropies. Case studies indicate that when a rock formation contains high dip-angle fractures or contains horizontal factures (e.g. bedding planes), it has very distinguished horizontal stresses. In these cases, the conventional isotropic method for estimating horizontal stresses may give erroneous results. Using the theory of anisotropy, horizontal stresses in the vertical transverse isotropy (VTI) and horizontal transverse isotropy (HTI) models are derived for determining in situ stresses in naturally fractured rocks. Comparing with the isotropic model, the VTI model predicts a higher minimum or maximum horizontal stress, which is suitable for shales. In contrast, the HTI model gives a lower minimum stress than the isotropic model. A combined model based on the VTI and HTI models is proposed for estimating the minimum horizontal stress in a naturally fractured formation containing natural fractures with different dip angles. Measured data in the Xujiahe gas reservoir in China reveal that the minimum horizontal stresses and formation breakdown pressures decrease as the fracture dip angles increase, which is consistent to the derived HTI model. Natural fractures can result in a decrease of the minimum horizontal stress by up to 3 MPa/km and a reduction of the formation breakdown pressure by up to 10 MPa/km in the studied area. Combining the proposed anisotropic model to the measured data of natural fractures and horizontal stresses, the assessment of in situ stresses and their impact on hydraulic fracturing are proposed. Case study demonstrates that the proposed model gives a good prediction of the minimum horizontal stresses in the naturally fractured reservoir.

A new method for predicting S-velocity, anisotropy and fracture parameters in horizontal transverse isotropy media

S-velocity, anisotropy and fracture parameters are of great importance in the development of horizontal transverse isotropy (HTI) reservoirs for the fracture attribute analysis and determination of fracture location. Increasing attention is gradually being paid to the accuracy of predicting them, especially for some well logs missing these parameters. Rock physics modelling is the one of the effective tools. For complex background media, simple spherical pores are no longer applicable. Multi-types of pores, the main component of the complex isotropic background, need to be considered using effective media model. For anisotropic media, Hudson and Schoenberg models are the classic theories for HTI fractures. However, the pitfall of Hudson model resides in the restrict of small crack density assumptions, that is not useful for most fractured stratum with higher crack density. To improve the applicability and quality of Hudson model, Padé approximation, based on Hudson first and second order expansions, is introduced. With the combination of the approximation and Schoenberg model, the new relationship of the fracture parameters and stiffness matrix are derived. On basis of this relationship, S-velocity, anisotropy and fracture parameters can be calculated. Compared to the Hudson combination method, the new proposed method shows significant advantages on the accuracy and validity of the estimated parameters for the model analysis and real well data in higher crack density, which can provide favourable data support for the exploration and development of fractured reservoirs.

Seismic Anisotropic Fluid Identification in Fractured Carbonate Reservoirs

Seismic fluid identification plays an important role in reservoir exploration and development. Natural vertical fractures are common in carbonate rocks, it is essential to consider fracture-induced anisotropy in the fluid identification of fractured carbonate reservoirs. We have developed a novel Bayesian elastic impedance variation with an angle and azimuth (EIVAZ) inversion approach for directly estimating the fracture fluid indicator (FFI), which can avoid cumulative errors produced in the indirect calculation process. Under the assumption of weak anisotropy and a small incident angle, we first derive a new approximate PP-wave coefficient for horizontal transverse isotropic (HTI) media. Analysis shows that the new approximation has reasonable accuracy at angles of incidence less than 30°. To estimate the FFI from observed azimuthal P-wave seismic reflection data, we further deduce the azimuthal EI equation and establish a two-step inversion workflow. Finally, the proposed approach is demonstrated by tests on a synthetic data example and a field data set of a fractured carbonate reservoir in the Sichuan Basin (China). Results show that the model parameters can be reasonably estimated even with moderate noise levels. The estimated FFI and quasi-normal fracture weakness show relatively high values at the location of reservoirs, which reliably indicate a fractured gas-bearing reservoir.

Analysis of AVAZ Seismic Forward Modeling of Fracture-Cavity Reservoirs of the Dengying Formation, Central Sichuan Basin

For the purpose of clarifying the seismic response characteristics of fractured-cavity reservoirs of Dengying Formation in the central Sichuan Basin, the paper first intends to establish three geological models of fracture cave reservoirs based on drilling, logging, and core data of the Dengying Formation in the central Sichuan Basin. Then, the formation reflection is calculated with reference to anisotropic Horizontal Transverse Isotropy (HTI) medium. Finally, further research on Amplitude Variation with Azimuth (AVAZ) seismic forward modeling has been conducted to clarify the seismic response characteristics of different reservoir types in the study area. The results suggest that: Seismic response characteristics of fractured-cavity reservoirs are controlled by incident angle and azimuth angle of seismic waves in different types of reservoirs. The incident angle of the seismic wave controls the difference in amplitude caused by different micro-fracture densities, and the azimuth angle controls the identification ability of the micro-fracture direction. The increase in incident angle brings about a gradual decline in amplitude. The magnitude reaches the highest when the azimuth is parallel to the normal direction of the fracture surface; however, it’ll come down to the lowest as the azimuth is perpendicular to the normal direction of the fracture surface. The fracture density fails to affect the amplitude as long as the azimuth angle is parallel to the direction of the fracture. However, the decreased amplitude reflects the increasing fracture density as the azimuth angle is identical to the normal direction of the fracture surface. The comparison between the theoretical model of three different types of fractured-cavity reservoirs and the actual uphole trace shows that the model has high accuracy. The prospect of seismic identification of fractured-cavern reservoirs, based on the results, can provide us with feasible and applicable evidence for future research on seismic identification of reservoirs and prediction of fracture distribution in the Dengying Formation of central Sichuan.

Simultaneous Bayesian inversion for effective anisotropy parameters and source locations: a physical modelling study

SUMMARY Estimating microseismic event locations is important for applications of geophysical monitoring, including hydraulic fracturing and carbon-capture and storage. Field sites for these applications are typically located in sedimentary basins that include finely stratified sediments, particularly around the target depth of the application. The fine stratification causes vertical transverse isotropy (VTI) for seismic wave propagation. In addition, such sediments often exhibit a vertically fractured rock mass that can cause horizontal transverse isotropy (HTI). Therefore, geophysical monitoring can be strongly affected by the occurrence of anisotropy caused by sets of aligned vertical fractures in finely horizontally layered media. While both HTI and VTI theories exist, a more efficient approximation to include both effects is by effective orthorhombic (ORT) models. To account for such anisotropy in microseismic monitoring, we simultaneously estimate ORT parameters, perforation shot locations, and microseismic event locations with Bayesian methods based on direct P-wave arrival times. A comparison to a HTI parametrization is carried out to examine anisotropy-model choice. The quasi-P-wave group velocities in HTI and ORT media are approximated by linearization. Anisotropy parameters are estimated with Markov chain Monte Carlo sampling that includes parallel tempering and principal-component diminishing adaptation to ensure efficient sampling of the parameter space. In contrast to deterministic inversion, our probabilistic non-linear approach includes uncertainty quantification by approximating the posterior probability density with an ensemble of model-parameter sets for effective anisotropy parameters, microseismic event locations, and horizontal locations of perforation shots. The noise standard deviation of P-arrival times is also treated as unknown. The inversion is carried out for simulated data, and for data from a physical laboratory model. In the latter case, an anisotropic layer is represented by a phenolic canvas electric material, and a star-shaped surface-receiver configuration is used to record microseismic signals. Results show that obtaining unbiased event locations requires an appropriate choice of anisotropy model and the ability to resolve anisotropy parameters. The resolution of anisotropy parameters requires significantly more data information from microseismic acquisition than required for isotropic models. Therefore, we study several acquisition scenarios for simulated and laboratory data. Assuming an HTI model in the inversion when data originate from an ORT medium causes systematic errors in event locations. However, appropriate resolution of ORT parameters requires a large acquisition aperture, an accurate perforation-shot timing, and the combination of surface acquisition with a vertical downhole array. These scenarios provide new knowledge about field requirements to produce sufficient information for the resolution of microseismic event locations in the presence of ORT effects in the data.

Anisotropic Poroelasticity and AVAZ Inversion for in Situ Stress Estimate in Fractured Shale-Gas Reservoirs

Knowledge of <italic xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">in situ</i> stress is of great significance for hydraulic fracture stimulating of unconventional reservoirs. Quantitative estimation of <italic xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">in situ</i> stress, especially in the far field, is a major challenge. This research mainly focuses on developing a novel Bayesian AVAZ inversion approach to estimate <italic xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">in situ</i> stress of fractured shale-gas reservoirs with horizontal transversely isotropic (HTI) symmetry. Using the generalized Hooke’s law and Schoenberg’s linear slip model, we first deduce the anisotropic horizontal stress equation in an HTI medium formed by a single set of vertically aligned fractures embedded in an isotropic background rock. Based on the critical porosity model, we then obtain the saturated stiffness matrix with vertical effective stress-sensitive parameters and dry fracture weaknesses using the relationship between vertical effective stress and porosity. Combining the scattering function and the perturbed stiffness matrix, we deduce a linearized PP-wave reflection coefficient as a function of fluid bulk modulus, vertical effective stress-sensitive parameter, dry-rock P- and S-wave moduli, density, and fracture density. Finally, we propose a novel Bayesian amplitude variation with azimuth (AVAZ) inversion constrained by the Cauchy regularization and low-frequency regularization to estimate these model parameters, which are further used to calculate <italic xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">in situ</i> stress. The analysis of synthetic data demonstrates that <italic xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">in situ</i> stress can be reasonably estimated even with moderate noise. A field data set test reveals that the inversion results agree well with the well log interpretation, and the proposed approach can generate meaningful results that are useful for seismic identification of potential fracturing barriers during fracturing stimulation of shale-gas reservoirs.

Bayesian Seismic Azimuth-Difference Inversion of Horizontal Transversely Isotropic Media for Low-Frequency Component of Fracture Weaknesses in Laplace-Fourier Domain

Fracture weakness is one of the most important anisotropic parameters used to characterize the fractures and identify the fluids. The model of horizontal transversely isotropic (HTI) medium is usually utilized in seismic azimuthal inversion for the fracture weaknesses. Low-frequency component of fracture weaknesses plays a significant role in seismic fracture characterization and fluid identification due to the deficiency of low-frequency component in acquired seismic azimuthal data. The commonly used approaches to estimate low-frequency component include the smoothing model constraints and the damped wave field in complex-frequency domain. Following the Bayesian framework, we propose a novel approach used for compensating the low-frequency component of fracture weaknesses in Laplace-Fourier domain. Firstly, we reconstruct the seismic forward solver in Laplace-Fourier domain to obtain the low-frequency component of fracture weaknesses. Then, we propose a method of seismic azimuth-difference inversion for fracture weaknesses in Laplace-Fourier domain in a Bayesian framework. Finally, both synthetic and field data examples are used to demonstrate the superiority and stability of the proposed inversion approach. Compared with the conventional inversion approach, the proposed approach can reduce the dependence on the initial model of model parameters and weaken the effect of missing low-frequency components of fracture weaknesses in azimuthal seismic data, and it may help to improve the inversion accuracy of fracture weaknesses and reduce the uncertainty of inversion results.

Prior Analysis in Determination of TI Anisotropy Type through Well-Based Modelling: A Case Study on the Deep Water Environment

The existence of anisotropy phenomena in the subsurface will affect the image quality of seismic data. Hence a prior knowledge of the type of anisotropy is quite essential, especially when dealing with deep water targets. The preliminary result of the anisotropy of the well-based modelling in deep water exploration and development is discussed in this study. Anisotropy types are modelled for Vertical Transverse Isotropy (VTI) and Horizontal Transverse Isotropy (HTI) based on Thomsen Parameters of ε and γ. The parameters are obtained from DSI Logging paired with reference δ value for modelling. Three initial conditions are then analysed. The first assumption is isotropic, in which the P-Wave Velocity, S-Wave Velocity, and Density Log modelled at their in-situ condition. The second and third assumptions are anisotropy models that are VTI and HTI. In terms of HTI, the result shows that the model of CDP Gather in the offset domain has a weak distortion in Amplitude Variation with Azimuth (AVAz). However, another finding shows a relatively strong hockey effect in far offset, which indicates that the target level is a VTI dominated type. It is supported by the geomechanical analysis result in which vertical stress acts as the maximum principal axis while horizontal stress is close to isotropic one. To sum up, this prior anisotropy knowledge obtained based on this study could guide the efficiency guidance in exploring the deep water environment.

Calculation method and characteristic analysis of dispersion curves of Rayleigh channel waves in transversely isotropic media

Coal seams have beddings and fissures and are typically anisotropic media. Current channel wave theories are mainly based on isotropic media, and few studies exist on the dispersion characteristics of Rayleigh channel waves in anisotropic models, such as transversely isotropic (TI) media. We chose the generalized reflection-transmission coefficient method to solve the dispersion curves of Rayleigh channel waves in TI media. However, it is difficult to solve the associated dispersion equations of Rayleigh channel waves using this method directly. Therefore, we have extended the generalized reflection-transmission coefficient method and determined the improved accuracy through numerical simulation. We analyzed the dispersion characteristics of Rayleigh channel waves of several typical coal seam models in TI media. The results showed that in the three-layer model, the difference in fundamental-mode dispersion curves between vertically transversely isotropic (VTI) media and isotropic media was relatively small; however, the differences in the higher order dispersion curves were slightly larger. The difference in the Airy phase velocity between horizontal transversely isotropic (HTI) and isotropic media was relatively large. When the coefficient of variation in the qP waves ([Formula: see text]) was greater than 0, the fundamental-mode and first-order phase velocity curves of HTI media exhibited an evident intersection at the head end. In the dirt-band-containing coal seam model, within the 350 and 550 Hz band, the high-frequency velocity of fundamental-mode phase velocity curve of isotropy and HTI media was slightly higher than the low-frequency velocity, which is a notable phenomenon.

Multiscale frequency-domain seismic inversion for fracture weakness

Amplitude variation with offset and azimuth (AVOAz) inversion is an effective tool to invert the azimuthal seismic reflection data for fracture weaknesses, which play an important role in seismic characterization of fractures. Conventional AVOAz inversion is implemented in the time domain, which simultaneously uses full-frequency components of the seismic data causing an unstable and inaccurate inversion result in the case of noisy seismic data. Here we propose a novel multiscale frequency-domain seismic inversion approach to improve resolution and accuracy of fracture weakness estimates. Based on new derived frequency-domain expression of azimuthal seismic amplitude difference for a horizontal transversely isotropic (HTI) medium, we build the kernel function incorporated with the Fourier operator, which avoids the Fourier inverse transform in the frequency-domain inversion. Low frequency information in seismic data is often missing or contaminated with noises, thus we establish an inversion objective function combining low frequency regularization term and Cauchy sparse regularization term in the Bayesian framework. We adopt the multiscale strategy and perform inversion successively from low to high frequency group utilizing a limited number of frequency components with a high signal-to-noise (S/N) ratio. In addition, we compare the multiscale frequency-domain inversion approach, the frequency-domain simultaneous inversion approach, and the time-domain inversion approach using synthetic data and field data. Synthetic example demonstrates that the cross-correlation coefficients (CCs) between the true fracture weaknesses and the inversion results obtained by multiscale frequency-domain inversion approach are above 0.83 even with a S/N of 2. Compared to the time-domain inversion approach and the frequency-domain simultaneous inversion approach, the inversion results with multiscale frequency-domain inversion approach have higher resolution and accuracy. Field data example further validates the feasibility and superiority of the proposed multiscale frequency-domain inversion approach.

Characteristics of dispersion curves for Love channel waves in transversely isotropic media

Coal seams have a pronounced bedding structure with developed cracks and exhibit significant anisotropy. However, few studies have examined the frequency dispersion properties of channel waves in anisotropic coal seams. In this study, numerical solutions are calculated using the generalized reflection-transmission coefficient method for the dispersion curves of Love channel waves in vertical transversely isotropic (VTI) and horizontal transversely isotropic (HTI) medium models. Moreover, the frequency dispersion characteristics of Love channel waves in several typical transversely isotropic models are analyzed. We find that the dispersion curves for isotropic and VTI media differ significantly. In addition, the phase and Airy-phase velocities in VTI media are higher than those in isotropic media. Thus, neglecting this difference in practical channel wave detection will result in large detection errors. The dispersion curves for the isotropic and HTI media do not differ significantly, and the Airy-phase velocities of various modes are similar. The group-velocity curve for a coal seam model containing a dirt band is found to be extremely irregular. The fundamental-mode Airy phase is not pronounced, but the first-mode Airy phase can be clearly observed. Hence, first-mode channel waves are suitable for detecting dirt bands.

Azimuthal anisotropy analysis of wide-azimuth P-wave seismic data for fracture orientation and density characterization in a tight gas reservoir

The role of anisotropy in fracture detection has dramatically increased with the advent of wide-azimuth (WAZ) and high-density seismic acquisition. Fracture prediction using horizontal transverse isotropy (HTI) anisotropic theory is a useful tool for identifying reservoir characteristics. We have developed an approach for fracture density and orientation estimation based on the combination of a velocity variation with azimuth (VVAZ) and an amplitude variation with azimuth (AVAZ) analysis workflow. First, we sort the prestack WAZ data into offset vector tile (OVT) sectors and perform VVAZ inversion by elliptical velocity fitting of measured azimuth-differential traveltimes. In this step, we can predict the fast P-wave velocity, slow P-wave velocity, and fracture orientation. Second, we apply AVAZ inversion to extract more accurate predictions of the anisotropic gradient and fracture orientation. We implement the method with 3D prestack WAZ seismic data acquired in the Sichuan Basin, from the southwest part of China. The field data example indicates that the inversion results agree with geologic information and well-log imaging data, which confirm the effectiveness of this technology.

Radiation pattern analyses for seismic multi-parameter inversion of HTI anisotropic media

Abstract In seismic waveform inversion, selecting an optimal multi-parameter group is a key step to derive an accurate subsurface model for characterising hydrocarbon reservoirs. There are three parameterizations for the horizontal transverse isotropic (HTI) media, and each parameterization consists of five parameters. The first parameterization (P-I) consists of two velocities and three anisotropy parameters, the second (P-II) consists of five elastic coefficients and the third (P-III) consists of five velocity parameters. The radiation patterns of these three parameterizations indicate a strong interference among five parameters. An effective inversion strategy is a two-stage scheme that first inverts for the velocities or velocity-related parameters and then inverts for all five parameters simultaneously. The inversion results clearly demonstrate that P-I is the best parameterization for seismic waveform inversion in HTI anisotropic media.