scholarly journals Viscoelastic Fluid Factor Inversion and Application in Luojia Oilfield Based on Broadband Impedance

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-8
Author(s):  
Ruyi Zhang ◽  
Huazhong Wang
Keyword(s):  
Viscoelastic Fluid ◽  
Rock Physics ◽  
Impedance Method ◽  
Frequency Dependent ◽  
Fluid Identification ◽  
Fluid Factor ◽  
Impedance Inversion ◽  
Elastic Impedance ◽  
Sensitive Parameters ◽  
The Relationship

Based on the physical quantity of log data, the accurate identification of oil- and gas-bearing properties may be caused by the prestack inversion of fluid prediction, which will affect the success rate of exploration and development. Prestack data contain more information of amplitude and frequency. Using the frequency-dependent viscoelastic impedance equation and Bayesian inversion framework, the objective function of frequency-dependent elastic impedance inversion can be established to realize the frequency-dependent impedance inversion at different angles. According to the elastic impedance equation of the frequency-varying viscoelastic fluid factor, the relationship between elastic impedance and the frequency-dependent viscoelastic fluid factor is established, and the prestack seismic inversion method of the frequency-dependent viscoelastic fluid factor is studied. However, one of the important factors easily neglected is that we have been using logging data to establish fluid-sensitive parameters and the lithophysical version for fluid identification, so there are differences between logging and seismic frequency bands for fluid identification. The indicator factors with higher sensitivity to fluid can be selected by laboratory measurements. This article applies this method on Luojia oilfield data and verifies this method with log interpretation results, based on the sample of rock physics obtained in a low-frequency rock physics experiment; the technique of dispersion and fluid-sensitive parameters is studied, and the fluid prediction technology of a multifrequency band rock physics template is adopted, which can build the relationship between rock physical elastic parameters and fluid properties by the multifrequency broadband impedance method.

Azimuthally anisotropic elastic impedance inversion for fluid indicator driven by rock physics

Geophysics ◽  
2017 ◽  
Vol 82 (6) ◽  
pp. C211-C227 ◽  
Author(s):  
Xinpeng Pan ◽  
Guangzhi Zhang ◽  
Xingyao Yin
Keyword(s):  
Fractured Reservoirs ◽  
Low Frequency ◽  
Rock Physics ◽  
Real Data ◽  
Inversion Method ◽  
Anisotropic Rock ◽  
Weak Anisotropy ◽  
Fluid Identification ◽  
Anisotropic Elastic ◽  
Elastic Impedance

The normal-to-tangential fracture compliance ratio is usually used as a fracture fluid indicator (FFI) for fluid identification in fractured reservoirs. With a new parameterization for fracture weaknesses, we have defined a new FFI based on azimuthally anisotropic elastic impedance (EI) inversion and fractured anisotropic rock-physics models. First, we derived a new azimuthally anisotropic EI equation with a similar expression for the isotropic and anisotropic EI parts to remove the exponential correction of EI that is attributable to weak anisotropy. Then, we built a fractured anisotropic rock-physics model used for the estimation of well-log parameters for the normal and tangential fracture weaknesses, which built the initial background low-frequency trend of fracture weaknesses. Finally, based on the azimuthally anisotropic EI inversion method with the Cauchy-sparse and low-frequency information regularization, we estimated an FFI applied to fluid identification in fractured reservoirs. Tests on the synthetic and real data demonstrate that the anisotropic parameters related to fracture weaknesses can be estimated reasonably and stably and that our method appears to provide an alternative available for fluid identification in fractured reservoirs.

Matrix-fluid decoupling-based joint PP-PS-wave seismic inversion for fluid identification

Geophysics ◽  
2019 ◽  
Vol 84 (3) ◽  
pp. R477-R487 ◽  
Author(s):  
Bing-Yi Du ◽  
Wu-Yang Yang ◽  
Jing Zhang ◽  
Xue-Shan Yong ◽  
Jian-Hu Gao ◽  
...  
Keyword(s):  
Bulk Modulus ◽  
Reservoir Characterization ◽  
Joint Inversion ◽  
Rock Physics ◽  
Seismic Inversion ◽  
New Method ◽  
Converted Wave ◽  
Fluid Identification ◽  
Fluid Factor ◽  
Fluid Detection

Seismic fluid identification is the main goal of current prestack seismic inversion. Various kinds of fluid indicators are used for fluid detection in industry today. However, the existing methods cannot always provide reliable fluid prediction owing to the insensitivity to fluid response and the lack of converted wave constraints. The equivalent fluid bulk modulus is an effective fluid factor based on matrix-fluid decoupling, which can provide persuasive evidence for fluid detection. Combining poroelasticity theory and matrix-fluid decoupling theory, we have deduced a new PS-wave linear amplitude versus offset approximation equation that provides estimations of equivalent fluid bulk modulus, rigidity, porosity, and density. Then, the joint inversion of PP- and PS-waves based on matrix-fluid decoupling was executed in a Bayesian framework with constraints from rock physics and well-log data obtaining elastic parameter estimation of high precision directly. We tested the new method on a synthetic example and field multicomponent data, and the results indicated that the estimated fluid factor matched with well-data interpretation and geology information because of adding converted wave information and avoiding indirect inversion error. This demonstrated that the new method can enhance the quality of fluid detection and provide reliable geophysical evidence for reservoir characterization.

Characterization of shallow high-amplitude seismic anomalies in the Hoop Fault Complex, Barents Sea

2017 ◽  
Vol 5 (4) ◽  
pp. T607-T622 ◽  
Author(s):  
Satinder Chopra ◽  
Ritesh Kumar Sharma ◽  
Graziella Kirtland Grech ◽  
Bent Erlend Kjølhamar
Keyword(s):  
Barents Sea ◽  
Rock Physics ◽  
High Amplitude ◽  
Data Types ◽  
Impedance Inversion ◽  
To Come ◽  
Seismic Amplitudes ◽  
Diverse Data ◽  
Seismic Anomalies ◽  
Elastic Impedance

The shallow migrating hydrocarbon fluids in the western Barents Sea are usually found to be associated with high seismic amplitudes. We have attempted to characterize such shallow high-amplitude anomalies in the Hoop Fault Complex area of the western Barents Sea. The workflow is devised for discrimination of anomalies that are associated with the presence of hydrocarbons from those that are not, and quantifying them further includes the computation of a set of seismic attributes and their analyses. These attributes comprise coherence, spectral decomposition, prestack simultaneous impedance inversion, and extended elastic impedance attributes, followed by their analysis in an appropriate crossplot space, as well as with the use of rock-physics templates. Finally, we briefly evaluate the futuristic efforts being devoted toward the integration of diverse data types such as P-cable seismic as well as controlled-source electromagnetic data so as to come up with an integrated assessment for the prospects and to mitigate risk.

Deepwater reservoir heterogeneity delineation using rock physics and extended elastic impedance inversion: Nile Delta case study

2014 ◽  
Vol 2 (4) ◽  
pp. T205-T219 ◽  
Author(s):  
Ahmed Hafez ◽  
Folkert Majoor ◽  
John P. Castagna
Keyword(s):  
Nile Delta ◽  
Rock Physics ◽  
Amplitude Variation ◽  
Amplitude Variation With Offset ◽  
Impedance Inversion ◽  
Net To Gross ◽  
Deepwater Channel ◽  
Static Connectivity ◽  
Elastic Impedance

Deepwater channel reservoirs in the Nile Delta are delineated using extended elastic impedance inversion (EEI). We used the following workflow: seismic spectral blueing, rock physics and amplitude variation with offset modeling, seismic EEI and interpretation of the inverted cubes in terms of geologic facies, net-to-gross ratio, and static connectivity among depositional geobodies. Three subenvironments within the targeted reservoir interval were recognized using a combination of shale volume and [Formula: see text]-inverted cubes. These were used to generate 3D geobodies and a net-pay thickness map that were used in turn to calculate reservoir volumetrics. The results from the workflow matched well logs and could thus be used to investigate the potential of nearby prospects that have the same geologic settings.

Estimation of modified fluid factor and dry fracture weaknesses using azimuthal elastic impedance

Geophysics ◽  
2018 ◽  
Vol 83 (1) ◽  
pp. WA73-WA88 ◽  
Author(s):  
Huaizhen Chen ◽  
Yuxin Ji ◽  
Kristopher A. Innanen
Keyword(s):  
Reflection Coefficient ◽  
Synthetic Data ◽  
Tight Gas ◽  
Fracture Density ◽  
Fracture Detection ◽  
Data Set ◽  
Fluid Identification ◽  
Fluid Factor ◽  
Damped Least Squares ◽  
Elastic Impedance

We consider the problem of fluid identification and fracture detection in unconventional reservoir (tight gas sand and shale gas) characterization. We begin with a simplification of the stiffness parameters and the derivation of a linearized reflection coefficient and azimuthal elastic impedance (EI). The accuracy of the simplification is confirmed in application to gas-bearing fractured rocks with low porosity and small fracture density. We have developed a modified fluid factor that is more sensitive to fluid type and less influenced by porosity. A two-step inversion workflow is evaluated based on the derived linearized reflection coefficient and azimuthal EI, including (1) a damped least-squares inversion for azimuthal EI, constrained by an initial model, and (2) a Bayesian Markov chain Monte Carlo inversion for the modified fluid factor and dry fracture weaknesses. Stability and accuracy are examined with synthetic data, from which we conclude that the modified fluid factor and dry fracture weaknesses can be stably determined in the presence of moderate data error/noise. The stability of our approach is further confirmed on a fractured tight gas sand field data set, within which we observe that geologically reasonable parameters (Lamé constants, the modified fluid factor, and dry fracture weaknesses) are determined. We conclude that our inversion workflow and its underlying assumptions form realistic predictions/discriminations of reservoir fracture and fluid parameters.

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