Application of Wide-Azimuth Anisotropy Inversion Predicting Carbonate Fracture Intensity and Direction

2021 ◽  
Author(s):  
Tongcui Guo ◽  
Guihai Wang ◽  
Xinmin Song ◽  
Dongbo He ◽  
Jian Zhang ◽  
...  
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
Seismic Anisotropy ◽  
Fracture Prediction ◽  
Inversion Method ◽  
Fracture Density ◽  
Simultaneous Inversion ◽  
Fracture Intensity ◽  
Target Layer ◽  
Key Steps

Abstract Fractures in carbonate rock are both storing reservoirs and migrating channels for oil and gas, so such fractures are one of the key targets for oil exploration and development. Traditional fracture prediction methods by seismic data include ant tracking cube, coherence cube and other seismic attributes. Fractures predicted by these methods are less accurate. This paper introduces a wide-azimuth anisotropic inversion method to effectively predict the fracture density and direction in carbonates. a wide-azimuth seismic anisotropy inversion workflow is established to predict the fractures in carbonates, and consequently the fractured zones in the target layer. The key steps include: (1) carry out quality control and optimization of wide-azimuth seismic gathers; (2) conduct pre-stack simultaneous inversion of pre-stack seismic data at partial sub-offsets and sub-azimuths to obtain the Vp/Vs of the azimuths; (3) use Azimuthal Fourier Coefficient to calculate the anisotropic gradient and direction. Based on the anisotropic intensity and direction and elastic parameters in the study area, the density and direction of fractures are obtained. The prediction results show that in the study area, nearly SN-striking fractures are developed, which are chiefly tectonic fractures, and consistent with the imaging logging results. It has been proved that the method is reasonable and feasible, and the accuracy of fracture prediction is improved.

Simultaneous inversion of prestack seismic data for rock properties using simulated annealing

Geophysics ◽  
2002 ◽  
Vol 67 (6) ◽  
pp. 1877-1885 ◽  
Author(s):  
Xin‐Quan Ma
Keyword(s):  
Simulated Annealing ◽  
Seismic Data ◽  
Low Frequency ◽  
Optimization Procedure ◽  
P Wave ◽  
Rock Properties ◽  
Inversion Method ◽  
Inversion Algorithm ◽  
Simultaneous Inversion ◽  
Reflection Seismic

A new prestack inversion algorithm has been developed to simultaneously estimate acoustic and shear impedances from P‐wave reflection seismic data. The algorithm uses a global optimization procedure in the form of simulated annealing. The goal of optimization is to find a global minimum of the objective function, which includes the misfit between synthetic and observed prestack seismic data. During the iterative inversion process, the acoustic and shear impedance models are randomly perturbed, and the synthetic seismic data are calculated and compared with the observed seismic data. To increase stability, constraints have been built into the inversion algorithm, using the low‐frequency impedance and background Vs/Vp models. The inversion method has been successfully applied to synthetic and field data examples to produce acoustic and shear impedances comparable to log data of similar bandwidth. The estimated acoustic and shear impedances can be combined to derive other elastic parameters, which may be used for identifying of lithology and fluid content of reservoirs.

SIMULTANEOUS INVERSION FOR S-WAVE VELOCITY DENSITY FROM THE SV-SV WAVE

Geophysics ◽  
2020 ◽  
pp. 1-50
Author(s):  
Feng Zhang
Keyword(s):  
Wave Velocity ◽  
Oil And Gas ◽  
Incident Angle ◽  
Inversion Method ◽  
S Wave ◽  
Simultaneous Inversion ◽  
Pp Wave ◽  
Velocity Information ◽  
Using Data ◽  
Two Parameters

Knowledge of shear-wave velocity ( Vs) and density ( ρ) is essential for oil and gas reservoir detection and characterization. However, reliable recovery of both parameters, especially density, from the reflected PP-wave data is a difficult issue, because this inverse problem is highly illconditioned. The reflected SV-SV wave is easier to process than the PS-wave, and can provide better estimates of Vs and ρ than the PP-wave, because it is more sensitive to these parameters than the PP-wave. I present a simultaneous inversion for Vs and ρ based on a modified approximation of the SV-SV wave reflection coefficient. The modified equation includes only two parameters (natural logarithms of Vs and ρ) to be inverted, and it has high accuracy even at large incident angles and for strong impedance contrasts. I show that simultaneous inversion based on the modified approximation is well-posed when using data of small-to-moderate incident angle (20°-30°), and the misfit function can be easily regularized. The new simultaneous inversion method is applied to a SV-SV wave prestack dataset acquired from a 2D ninecomponent survey. The field data example demonstrates that the proposed method can recover stable and high-resolution density and S-wave velocity information, which can be used to investigate rock mineral composition, porosity and fluid content.

Simultaneous inversion of PP and PS seismic data

Geophysics ◽  
2006 ◽  
Vol 71 (3) ◽  
pp. R1-R10 ◽  
Author(s):  
Helene Hafslund Veire ◽  
Martin Landrø
Keyword(s):  
Seismic Data ◽  
Reservoir Characterization ◽  
Model Building ◽  
Joint Inversion ◽  
P Wave ◽  
Inversion Method ◽  
System Of Equations ◽  
S Wave ◽  
Data Set ◽  
Simultaneous Inversion

Elastic parameters derived from seismic data are valuable input for reservoir characterization because they can be related to lithology and fluid content of the reservoir through empirical relationships. The relationship between physical properties of rocks and fluids and P-wave seismic data is nonunique. This leads to large uncertainties in reservoir models derived from P-wave seismic data. Because S- waves do not propagate through fluids, the combined use of P-and S-wave seismic data might increase our ability to derive fluid and lithology effects from seismic data, reducing the uncertainty in reservoir characterization and thereby improving 3D reservoir model-building. We present a joint inversion method for PP and PS seismic data by solving approximated linear expressions of PP and PS reflection coefficients simultaneously using a least-squares estimation algorithm. The resulting system of equations is solved by singular-value decomposition (SVD). By combining the two independent measurements (PP and PS seismic data), we stabilize the system of equations for PP and PS seismic data separately, leading to more robust parameter estimation. The method does not require any knowledge of PP and PS wavelets. We tested the stability of this joint inversion method on a 1D synthetic data set. We also applied the methodology to North Sea multicomponent field data to identify sand layers in a shallow formation. The identified sand layers from our inverted sections are consistent with observations from nearby well logs.

The Fractured Prediction for Narrow-Azimuth Seismic Data of Carbonate

2014 ◽  
Vol 675-677 ◽  
pp. 1336-1340 ◽  
Author(s):  
Zhong Liang Liu ◽  
Yi Zeng ◽  
Ju Jia Liu
Keyword(s):  
Numerical Simulation ◽  
Stress Field ◽  
Seismic Data ◽  
Carbonate Reservoir ◽  
Fracture Prediction ◽  
Vital Importance ◽  
Applied Technology ◽  
Target Layer

It is vital importance to understand distribution and development of carbonate reservoir fractures for studying carbonate reservoir. Stimulate and acceptance conditions of study area in the desert are poor, and The seismic data is characterized by narrow azimuth. Limit of data has influence on fracture prediction of target layer. In this paper, the post-stack and pre-stack seismic data were used. At first , techniques of stress field numerical simulation was applied to predict the distribution of tectonic crack of the study area ; Secondly, because of the characteristics of narrow-azimuth seismic data, the paper applied technology of near and far offset attribute discrepancy of pre-stack data to predict the degree of development of cracks. Finally, effective fracture was predicted on the basis of development of the forecasted cracks.

scholarly journals Simultaneous Seismic Inversion for Reservoir Characterization at Poseidon Field, Browse Basin, Australia

2021 ◽  
Vol 4 (1) ◽  
Author(s):  
Suleman Mauritz Sihotang ◽  
Ida Herawati
Keyword(s):  
Oil And Gas ◽  
Reservoir Characterization ◽  
Research Area ◽  
Seismic Inversion ◽  
Inversion Method ◽  
Well Log ◽  
Gas Field ◽  
Simultaneous Inversion ◽  
Fluid Saturation ◽  
Oil And Gas Field

Seismic inversion method has been widely used to obtain reservoir property in an oil and gas field. In this research, one of inversion methods known as simultaneous inversion is used to analyze reservoir characterization at Poseidon Field, Browse Basin. Simultaneous inversion is applied to partial angle stack data and result in volume of Acoustic Impedance (AI), Shear Impedance (SI) and Lame parameter (LMR). The objective of this study is to determine distribution of sandstone lithology with gas saturated in Plover reservoir formation. Sensitivity analysis is done by cross-plotting elastic and Lame parameter from five well log data and analyzing lithology type and fluid saturation. Based on those cross-plots, lithological type can be identified from AI, λρ, µρ and λ/µ parameters. Meanwhile, the presence of gas can be discriminated using SI, λρ, and λ/µ parameters. Gas-saturated sandstone presence is characterized by Lambda-Rho value less than 50 GPa g cc-1 and Lambda over Mu value less than 0.8 GPa g cc-1. Maps of each parameter are generated at reservoir interval. Based on those maps, it can be concluded that gas sand spread out in the eastern and western areas of research area.

Anisotropy signatures in the Cooper Basin of Australia: Stress versus fractures

2016 ◽  
Vol 4 (2) ◽  
pp. SE51-SE61 ◽  
Author(s):  
Stephanie Tyiasning ◽  
Dennis Cooke
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
Seismic Anisotropy ◽  
Transverse Isotropy ◽  
Ground Truth ◽  
Tectonic Stress ◽  
Reverse Fault ◽  
Stress Regime ◽  
Velocity Anisotropy ◽  
Cooper Basin

Theoretically, vertical fractures and stress can create horizontal transverse isotropy (HTI) anisotropy on 3D seismic data. Determining if seismic HTI anisotropy is caused by stress or fractures can be important for mapping and understanding reservoir quality, especially in unconventional reservoirs. Our study area was the Cooper Basin of Australia. The Cooper Basin is Australia’s largest onshore oil and gas producing basin that consists of shale gas, basin-centered tight gas, and deep coal play. The Cooper Basin has unusually high tectonic stress, with most reservoirs in a strike-slip stress regime, but the deepest reservoirs are interpreted to be currently in a reverse-fault stress regime. The seismic data from the Cooper Basin exhibit HTI anisotropy. Our main objective was to determine if the HTI anisotropy was stress induced or fracture induced. We have compared migration velocity anisotropy and amplitude variation with offset anisotropy extracted from a high-quality 3D survey with a “ground truth” of dipole sonic logs, borehole breakout, and fractures interpreted from image logs. We came to the conclusion that the HTI seismic anisotropy in our study area is likely stress induced.

Bayesian lithology and fluid prediction from seismic prestack data

Geophysics ◽  
2008 ◽  
Vol 73 (3) ◽  
pp. C13-C21 ◽  
Author(s):  
Arild Buland ◽  
Odd Kolbjørnsen ◽  
Ragnar Hauge ◽  
Øyvind Skjæveland ◽  
Kenneth Duffaut
Keyword(s):  
Seismic Data ◽  
Rock Physics ◽  
Real Data ◽  
Feasibility Analysis ◽  
Bayesian Inversion ◽  
Inversion Method ◽  
Elastic Parameters ◽  
Data Set ◽  
Prior Probabilities ◽  
Simultaneous Inversion

A fast Bayesian inversion method for 3D lithology and fluid prediction from prestack seismic data, and a corresponding feasibility analysis were developed and tested on a real data set. The objective of the inversion is to find the probabilities for different lithology-fluid classes from seismic data and geologic knowledge. The method combines stochastic rock physics relations between the elastic parameters and the different lithology-fluid classes with the results from a fast Bayesian seismic simultaneous inversion from seismic data to elastic parameters. A method for feasibility analysis predicts the expected modification of the prior probabilities to posterior probabilities for the different lithology-fluid classes. The feasibility analysis can be carried out before the seismic data are analyzed. Both the feasibility method and the seismic lithology-fluid probability inversion were applied to a prospect offshore Norway. The analysis improves the probability for gas sand from 0.1 to about 0.2–0.4 with seismic data.

Find the rocks and the fluids will follow — AVO as a tool for lithology classification

2014 ◽  
Vol 2 (2) ◽  
pp. SC77-SC91 ◽  
Author(s):  
Kester D. Waters ◽  
Michael A. C. Kemper
Keyword(s):  
Case Studies ◽  
Seismic Data ◽  
Oil And Gas ◽  
Rock Physics ◽  
Amplitude Variation With Offset ◽  
Primary Means ◽  
Interpretation Process ◽  
Close Cooperation ◽  
Key Steps

Full-stack seismic interpretation continues to be the primary means of subsurface interpretation. However, the underlying impact of amplitude variation with offset (AVO) is effectively ignored or overlooked during the full-stack interpretation process. Recent advances in well-logging and rock physics techniques highlight the fact that AVO is a useful tool not only for detection of fluid anomalies, but also for the detection and characterization of lithology. We evaluated an overview of some of the key steps in the rock physics assessment of well logs and seismic data, and highlight the potential to move toward a new convention of interpretation on so-called lithology stacks. Lithology stacks may come in a variety of forms but should form the focus of interpretation efforts in the early part of the exploration and appraisal cycle. Several case studies were used to highlight that subtle fluid effects can only be extracted from the seismic data after careful assessment of the lithology response. These case studies cover a wide geography and variable geology and demonstrate that the techniques we tested are transferable and applicable across many different oil and gas provinces. The use of lithology stacks has many benefits. It allows interpretation on a single stack rather than many different offset or angle stacks. A lithology stack provides a robust, objective framework for lithostratigraphic interpretation and can be calibrated to offset wells when available. They are conceptually simple, repeatable, and transferable, allowing close cooperation across the different subsurface disciplines.

Integrated VTI model building with seismic data, geologic information, and rock-physics modeling — Part 1: Theory and synthetic test

Geophysics ◽  
2016 ◽  
Vol 81 (5) ◽  
pp. C177-C191 ◽  
Author(s):  
Yunyue Li ◽  
Biondo Biondi ◽  
Robert Clapp ◽  
Dave Nichols
Keyword(s):  
Seismic Data ◽  
Seismic Anisotropy ◽  
Model Building ◽  
Rock Physics ◽  
Seismic Inversion ◽  
Additional Information ◽  
Synthetic Test ◽  
Rock Physics Modeling ◽  
Physics Modeling ◽  
Geologic Information

Seismic anisotropy plays an important role in structural imaging and lithologic interpretation. However, anisotropic model building is a challenging underdetermined inverse problem. It is well-understood that single component pressure wave seismic data recorded on the upper surface are insufficient to resolve a unique solution for velocity and anisotropy parameters. To overcome the limitations of seismic data, we have developed an integrated model building scheme based on Bayesian inference to consider seismic data, geologic information, and rock-physics knowledge simultaneously. We have performed the prestack seismic inversion using wave-equation migration velocity analysis (WEMVA) for vertical transverse isotropic (VTI) models. This image-space method enabled automatic geologic interpretation. We have integrated the geologic information as spatial model correlations, applied on each parameter individually. We integrate the rock-physics information as lithologic model correlations, bringing additional information, so that the parameters weakly constrained by seismic are updated as well as the strongly constrained parameters. The constraints provided by the additional information help the inversion converge faster, mitigate the ambiguities among the parameters, and yield VTI models that were consistent with the underlying geologic and lithologic assumptions. We have developed the theoretical framework for the proposed integrated WEMVA for VTI models and determined the added information contained in the regularization terms, especially the rock-physics constraints.

Analyzing the Impacts of Meshing and Grid Alignment in Dual-Porosity Dual-Permeability Upscaling

2021 ◽  
pp. 1-20
Author(s):  
Ziming Xu ◽  
Juliana Y. Leung
Keyword(s):  
Fracture Network ◽  
Fracture Plane ◽  
Fracture Density ◽  
Shape Factors ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Multiple Length Scales ◽  
Fracture Intensity ◽  
Cumulative Production ◽  
The Difference

Summary The discrete fracture network (DFN) model is widely used to simulate and represent the complex fractures occurring over multiple length scales. However, computational constraints often necessitate that these DFN models be upscaled into a dual-porositydual-permeability (DPDK) model and discretized over a corner-point grid system, which is still commonly implemented in many commercial simulation packages. Many analytical upscaling techniques are applicable, provided that the fracture density is high, but this condition generally does not hold in most unconventional reservoir settings. A particular undesirable outcome is that connectivity between neighboring fracture cells could be erroneously removed if the fracture plane connecting the two cells is not aligned along the meshing direction. In this work, we propose a novel scheme to detect such misalignments and to adjust the DPDK fracture parameters locally, such that the proper fracture connectivity can be restored. A search subroutine is implemented to identify any diagonally adjacent cells of which the connectivity has been erroneously removed during the upscaling step. A correction scheme is implemented to facilitate a local adjustment to the shape factors in the vicinity of these two cells while ensuring the local fracture intensity remains unaffected. The results are assessed in terms of the stimulated reservoir volume calculations, and the sensitivity to fracture intensity is analyzed. The method is tested on a set of tight oil models constructed based on the Bakken Formation. Simulation results of the corrected, upscaled models are closer to those of DFN simulations. There is a noticeable improvement in the production after restoring the connectivity between those previously disconnected cells. The difference is most significant in cases with medium DFN density, where more fracture cells become disconnected after upscaling (this is also when most analytical upscaling techniques are no longer valid); in some 2D cases, up to a 22% difference in cumulative production is recorded. Ignoring the impacts of mesh discretization could result in an unintended reduction in the simulated fracture connectivity and a considerable underestimation of the cumulative production.

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