Quantifying the effect of capillarity on attenuation and dispersion in patchy-saturated rocks

We measured the extensional‐mode attenuation and Young's modulus in a porous sample made of sintered borosilicate glass at microseismic to seismic frequencies (0.05–50 Hz) using the forced oscillation method. Partial saturation was achieved by water imbibition, varying the water saturation from an initial dry state up to ∼99%, and by gas exsolution from an initially fully water‐saturated state down to ∼99%. During forced oscillations of the sample effective stresses up to 10 MPa were applied. We observe frequency‐dependent attenuation, with a peak at 1–5 Hz, for ∼99% water saturation achieved both by imbibition and by gas exsolution. The magnitude of this attenuation peak is consistently reduced with increasing fluid pressure and is largely insensitive to changes in effective stress. Similar observations have recently been attributed to wave‐induced gas exsolution–dissolution. At full water saturation, the left‐hand side of an attenuation curve, with a peak beyond the highest measured frequency, is observed at 3 MPa effective stress, while at 10 MPa effective stress the measured attenuation is negligible. This observation is consistent with wave‐induced fluid flow associated with mesoscopic compressibility contrasts in the sample's frame. These variations in compressibility could be due to fractures and/or compaction bands that formed between separate sets of forced‐oscillation experiments in response to the applied stresses. The agreement of the measured frequency‐dependent attenuation and Young's modulus with the Kramers–Kronig relations and additional data analyses indicate the good quality of the measurements. Our observations point to the complex interplay between structural and fluid heterogeneities on the measured seismic attenuation and they illustrate how these heterogeneities can facilitate the dominance of one attenuation mechanism over another.

Section: Discussionmentioning

confidence: 99%

Laboratory measurements of seismic attenuation and Young's modulus dispersion in a partially and fully water‐saturated porous sample made of sintered borosilicate glass

Chapman

Quintal

Holliger

et al. 2018

“…In the presence of strong capillarity, Gassmann's equation needs to be modified to take the interfacial tension between the fluid patches into account (Qi et al . ; Qi, Müller, and Rubino ). On the other hand, for large fluid heterogeneities (

b ≫ l_{d}

), the fluid pressure has no time to equilibrate and will remain piecewisely constant within each fluid phase.…”

Section: Saturation Scales and Wave‐induced Pressure Diffusionmentioning

confidence: 99%

“…In the first part, we analyse the effect of the saturation scale on the AI and attenuation using the patchy saturation model of Qi et al . (). Based on this model, we compute the dynamic‐equivalent viscoelastic reflection coefficient for a patchy‐saturated reservoir and study the scale effect on seismic amplitudes.…”

Section: Introductionmentioning

confidence: 97%

Saturation scale effect on time‐lapse seismic signatures

Müller

Gurevich

2016

Self Cite

Quantitative interpretation of time‐lapse seismic signatures aims at assisting reservoir engineering and management operations. Time‐lapse signatures are thought to be primarily induced by saturation and pressure changes. Core‐flooding and reservoir flow simulations indicate that a change of the driving forces during dynamic fluid injection gives rise to a varying saturation scale. This saturation scale is yet another variable controlling the time‐lapse seismic signal. In this work, we investigate the saturation scale effect on time‐lapse seismic signatures by analysing simple modelling scenarios. We consider three characteristic saturation scales, ranging from few millimetres to metres, which may form during gas injection in an unconsolidated water‐saturated reservoir. Using the random patchy saturation model, we compare the corresponding acoustic signatures, i.e., attenuation, reflectivity, and seismic gather associated with each saturation scale. The results show that the millimetre saturation scale produces minimum attenuation and the same seismic signatures with those obtained from the elastic modelling. The centimetre saturation scale produces maximum attenuation, whereas the metre saturation scale causes highest velocity dispersion. The analyses of the time shift and amplitude change indicate that ignoring a time‐dependent saturation scale can result in biased estimation/discrimination of the saturation and the fluid pressure. In particular, the 4D signal can be strongly affected by the saturation‐scale change when the reservoir gas saturation is low and the effective pressure is high. In the presence of an increasing (decreasing) saturation scale during injection, interpreting an observed time shift and amplitude change using the Gassmann model will lead to underestimation (overestimation) of the change in gas saturation and fluid pressure. We show that including the effects of capillarity and residual saturation into the rock physics modelling can potentially reduce the interpretation uncertainty due to the saturation‐scale change.

“…; Qi et al . ). Therefore, if these observations are transferable to the borehole environment, then attenuation of sonic waves will be a useful attribute for reservoir characterization, overpressure zone detection and fluid monitoring in time‐lapse process during enhanced oil recovery.…”

Section: Introductionmentioning

confidence: 97%

Compensating elastic transmission losses for P‐wave attenuation estimation from sonic logs

Liang

Müller

Tang

et al. 2019

Self Cite

The decay of seismic amplitude is caused by a variety of physical phenomena that can be divided broadly into elastic transmission losses (including geometrical spreading, interface transmission losses and scattering attenuation) and intrinsic attenuation, where wave energy is converted into heat due to viscous friction. The so‐called statistical averaging method is currently considered as the most advanced sonic wave attenuation estimation method, and there exist various implementations of this method. But the way elastic transmission losses – that mask the true intrinsic attenuation – are compensated for appears to be an issue and in some cases this correction has been overlooked. In this paper, we revisit the statistical averaging method for intrinsic attenuation estimation with particular focus on the role of elastic transmission losses. Through synthetic examples, we demonstrate the importance of compensating for elastic transmission losses even if the variation of velocity and density with depth is not notable. Our implementation of the method uses finite‐difference simulations thereby providing a versatile and accurate way to generate synthetic seismograms. We use a combination of elastic and viscoelastic finite‐difference simulations to demonstrate the significant error without accurate compensation of the elastic transmission losses. We apply our implementation of the method to sonic waveforms acquired in an exploration well from Browse basin, Australia. The resulting intrinsic attenuation estimates are indeed indicative of gas‐saturated zones identified from petrophysical analysis in which viscous friction are thought to be of importance.