Calibration of prestack simultaneous impedance inversion using rock physics

Singleton, Scott; Keirstead, Rob

doi:10.1190/1.3535435

Cited by 4 publications

(2 citation statements)

References 12 publications

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“…The ideal procedure for treating fluid substitution in sub‐resolution sand–shale sequences is to first downscale using the model presented in the previous section, which involves inverting the properties of the sub‐resolution sand (with dispersed shale) and shale end members, applying Gassmann's fluid substitution to the sand or to the structural shale and, then, Backus averaging back to the original scale. This procedure, however, has many practical limitations as it is very sensitive to errors in estimated sand fraction and sand/shale properties and becomes particularly unstable at small sand/shale fractions (Katahara ; Skelt ,b; Singleton and Keirstead, ; Dejtrakulwong and Mavko ). Moreover, it is not always possible to realise or attain a coarse‐scale sonic measurement (

V p

V s

) by mixing fixed (or constant value) end member sand/shale properties as described in the previous section.…”

Section: Fluid Substitution At the Measurement Scalementioning

confidence: 99%

Rock physics model for seismic velocity & fluid substitution in sub‐resolution interbedded sand–shale sequences

Saxena

Hofmann

Dolan

et al. 2018

Geophysical Prospecting

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The measured geophysical response of sand–shale sequences is an average over multiple layers when the tool resolution (seismic or well log) is coarser than the scale of sand–shale mixing. Shale can be found within sand–shale sequences as laminations, dispersed in sand pores, as well as load bearing clasts. We present a rock physics framework to model seismic/sonic properties of sub‐resolution interbedded shaly sands using the so‐called solid and mineral substitution models. This modelling approach stays consistent with the conceptual model of the Thomas–Stieber approach for estimating volumetric properties of shaly sands; thus, this work connects established well log data‐based petrophysical workflows with quantitative interpretation of seismic data for modelling hydrocarbon signature in sand–shale sequences. We present applications of the new model to infer thickness of sand–shale lamination (i.e., net to gross) and other volumetric properties using seismic data. Another application of the new approach is fluid substitution in sub‐resolution interbedded sand–shale sequences that operate directly at the measurement scale without the need to downscale; such a procedure has many practical advantages over the approach of “first‐downscale‐and‐then‐upscale” as it is not very sensitive to errors in estimated sand fraction and end member sand/shale properties and remains stable at small sand/shale fractions.

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V p

V s

) by mixing fixed (or constant value) end member sand/shale properties as described in the previous section.…”

Section: Fluid Substitution At the Measurement Scalementioning

confidence: 99%

Rock physics model for seismic velocity & fluid substitution in sub‐resolution interbedded sand–shale sequences

Saxena

Hofmann

Dolan

et al. 2018

Geophysical Prospecting

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“…Fluid replacement modeling (FRM) is a valuable tool for modeling and analyzing the seismic responses to various fluid scenarios (Smith et al, 2003). The technique has had a significant impact on seismic attribute studies because it allows the interpreter to generate seismic responses for reservoirs under varying fluid conditions (Singleton and Kierstead, 2009;Yuping et al, 2010;Rizwan et al, 2018). In FRM, the pore fluids are replaced from a known saturation to a new saturation level, and new acoustic parameters are theoretically calculated.…”

Section: Introductionmentioning

confidence: 99%

Amplitude variation with offset (AVO) analysis via fluid replacement modeling (FRM) for characterizing the reservoir response of Cretaceous sand interval

Mughal¹,

Akhter²

2020

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The reservoir pore fluid at various saturation levels can be modeled and analyzed through fluid replacement modeling (FRM) by applying Gassmann's theory. The FRM technique was applied to a gas-prone reservoir (Cretaceous C-sand interval) of the Lower Goru Formation in the Sawan gas field, Middle Indus Basin, Pakistan. 3D post-stack seismic data and wireline log data of two exploration wells (Sawan-01 and Sawan-08) were utilized in the study. The petrophysical analysis of wells was carried out to initially predict the gas-bearing zones of the reservoir interval at well locations, and later on to predict areas away from the well through seismic to well tie. The amplitude variation with offset (AVO) behavior was analyzed by replacing the in situ fluid saturation level with a modeled 80% gas and 20% water saturation in the reservoir. The elastic properties of the reservoir sand were estimated through rock physics based on Gassmann equations. The AVO response under both in situ and FRM conditions indicated that the reservoir gas sand exhibits a typical class IV signature. The increase of reflection amplitude with angle in FRM synthetic gathers showed AVO sensitivity to changes in fluid type and saturation. The change in reservoir parameters with a change in fluid saturation levels and their AVO response was well-captured in the analysis for effective identification of lithology and fluid concentration in the reservoir. Moreover, the methodology followed in this study will be helpful for better characterizing hydrocarbon-bearing reservoirs within the study region and in various other parts of the world.

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Fluid substitution for thinly interbedded sand-shale sequences using the mesh method

Dejtrakulwong

Mavko

2016

GEOPHYSICS

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Gassmann’s fluid substitution model is intended for a monomineralic, homogeneous porous rock, in which pore pressures induced by applied loads can equilibrate throughout the pore space. These assumptions are violated when Gassmann’s equations are applied to measurements that represent effective medium averages over subresolution layers of alternating sand and shale. The conventional procedure for treating this problem has been to first downscale; i.e., estimate the properties of the fine-scale sand and shale endmembers from the coarse-scale measurements, apply Gassmann’s fluid substitution to the sand only, and then Backus average back to the original scale. This procedure, however, is very sensitive to errors in estimated sand fraction and shale properties and becomes particularly unstable at small sand fractions. A new method for fluid substitution combines rock-physics models for dispersed and interbedded sand-shale systems, which are often approximated with Reuss or lower Hashin-Shtrikman interpolations between endmembers quartz mineral, clean sand, and shale. When expressed as P-wave compliance versus porosity, these trends become approximately linear. The Backus average of the normal incidence P-wave compliance of thinly layered mixtures of various sand-shale facies is also a linear trend with porosity. As a result, the upscaled fluid substitution change of compliance of any point within the dispersed or layered sand-shale system is approximately proportional to the fluid-substituted change of compliance of the clean sand endmember, scaled by the ratio of effective porosity to clean sand porosity. The result is a fluid substitution procedure that operates directly at the measurement scale, without the need to downscale the measurements, while still changing fluid in the sand layers only.

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Calibration of prestack simultaneous impedance inversion using rock physics

Cited by 4 publications

References 12 publications

Rock physics model for seismic velocity & fluid substitution in sub‐resolution interbedded sand–shale sequences

Rock physics model for seismic velocity & fluid substitution in sub‐resolution interbedded sand–shale sequences

Amplitude variation with offset (AVO) analysis via fluid replacement modeling (FRM) for characterizing the reservoir response of Cretaceous sand interval

Fluid substitution for thinly interbedded sand-shale sequences using the mesh method

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