Rock properties of smectite- and ooze-rich claystones

Geophysics ◽  
2015 ◽  
Vol 80 (1) ◽  
pp. D89-D98 ◽  
Author(s):  
Bente Øygarden ◽  
Helge Løseth ◽  
Sigurd Njerve
Keyword(s):  
Wave Velocity ◽  
Rock Properties ◽  
Environmental Scanning ◽  
S Wave ◽  
Amplitude Variation With Offset ◽  
Lower Miocene ◽  
Lower Oligocene ◽  
Upper Oligocene ◽  
Northern North Sea ◽  
New Equation

Parameters measured by well logs define rock properties and seismic reflections at lithology interfaces. Parameters from standard embedding claystones are normally used when calculating the top sand amplitude variation with offset (AVO) response, but this might give erroneous results when the real claystone rock properties deviate from the standard. Using cuttings and high-quality wireline logs from well 34/8-A-33 H above the Visund field in the northern North Sea, we evaluated rock properties of the Pleistocene glaciomarine claystones, Lower Miocene and Upper Oligocene oozy claystones, Lower Oligocene and Eocene smectite-rich claystones, and two interbedded sands. Glaciomarine claystones fit best with the Greenberg-Castagna equation and have the highest measured velocities even though they are the shallowest buried sediments. Environmental scanning electron microscope analysis proves the Lower Miocene and Upper Oligocene claystones to be oozy. The amount of low-density oozy material causes significant shifts in the log curves and makes the ooze-rich claystones plot far off the trend given by the Greenberg-Castagna equation. We, therefore, developed a new equation for S-wave velocity prediction for ooze-rich claystones with average densities between [Formula: see text] and [Formula: see text]. The [Formula: see text] ratios increase with depth in the Lower Oligocene and Eocene claystones of the Hordaland Group, and we interpreted this to reflect a downward increase in the amount of smectite, which existence was proven by X-ray diffraction analysis. We modeled how the seismic response at the top of a sand changes with embedding claystone type, saturation fluid, and offset. In glaciomarine claystones, the top of a brine-saturated sand corresponds to a negative trough reflection, in ooze-rich claystones to a positive peak reflection, and in smectite-rich claystones the reflection amplitude is close to zero. The predicted AVO response of sands in oozy claystones is highly dependent on whether the measured or calculated S-wave velocity has been used in the modeling.

Interpretation of AVO anomalies

Geophysics ◽  
2010 ◽  
Vol 75 (5) ◽  
pp. 75A3-75A13 ◽  
Author(s):  
Douglas J. Foster ◽  
Robert G. Keys ◽  
F. David Lane
Keyword(s):  
Wave Velocity ◽  
Seismic Data ◽  
P Wave ◽  
Rock Properties ◽  
Light Hydrocarbons ◽  
S Wave ◽  
Amplitude Variation With Offset ◽  
P Wave Velocity ◽  
Fluid Properties ◽  
Porosity Changes

We investigate the effects of changes in rock and fluid properties on amplitude-variation-with-offset (AVO) responses. In the slope-intercept domain, reflections from wet sands and shales fall on or near a trend that we call the fluid line. Reflections from the top of sands containing gas or light hydrocarbons fall on a trend approximately parallel to the fluid line; reflections from the base of gas sands fall on a parallel trend on the opposing side of the fluid line. The polarity standard of the seismic data dictates whether these reflections from the top of hydrocarbon-bearing sands are below or above the fluid line. Typically, rock properties of sands and shales differ, and therefore reflections from sand/shale interfaces are also displaced from the fluid line. The distance of these trends from the fluid line depends upon the contrast of the ratio of P-wave velocity [Formula: see text] and S-wave velocity [Formula: see text]. This ratio is a function of pore-fluid compressibility and implies that distance from the fluid line increases with increasing compressibility. Reflections from wet sands are closer to the fluid line than hydrocarbon-related reflections. Porosity changes affect acoustic impedance but do not significantly impact the [Formula: see text] contrast. As a result, porosity changes move the AVO response along trends approximately parallel to the fluid line. These observations are useful for interpreting AVO anomalies in terms of fluids, lithology, and porosity.

Relating Acoustic Anisotropy to Kerogen Content in Unconventional Formations - A Case Study in A Kerogen-Rich Unconventional Carbonate

2021 ◽  
Author(s):  
Yair Gordin ◽  
Thomas Bradley ◽  
Yoav O. Rosenberg ◽  
Anat Canning ◽  
Yossef H. Hatzor ◽  
...  
Keyword(s):  
Wave Velocity ◽  
Water Saturation ◽  
Well Logs ◽  
Rock Properties ◽  
Thermal Maturity ◽  
Burial Diagenesis ◽  
S Wave ◽  
Velocity Anisotropy ◽  
Thermal Maturation ◽  
Wide Range

Abstract The mechanical and petrophysical behavior of organic-rich carbonates (ORC) is affected significantly by burial diagenesis and the thermal maturation of their organic matter. Therefore, establishing Rock Physics (RP) relations and appropriate models can be valuable in delineating the spatial distribution of key rock properties such as the total organic carbon (TOC), porosity, water saturation, and thermal maturity in the petroleum system. These key rock properties are of most importance to evaluate during hydrocarbon exploration and production operations when establishing a detailed subsurface model is critical. High-resolution reservoir models are typically based on the inversion of seismic data to calculate the seismic layer properties such as P- and S-wave impedances (or velocities), density, Poisson's ratio, Vp/Vs ratio, etc. If velocity anisotropy data are also available, then another layer of data can be used as input for the subsurface model leading to a better understanding of the geological section. The challenge is to establish reliable geostatistical relations between these seismic layer measurements and petrophysical/geomechanical properties using well logs and laboratory measurements. In this study, we developed RP models to predict the organic richness (TOC of 1-15 wt%), porosity (7-35 %), water saturation, and thermal maturity (Tmax of 420-435⁰C) of the organic-rich carbonate sections using well logs and laboratory core measurements derived from the Ness 5 well drilled in the Golan Basin (950-1350 m). The RP models are based primarily on the modified lower Hashin-Shtrikman bounds (MLHS) and Gassmann's fluid substitution equations. These organic-rich carbonate sections are unique in their relatively low burial diagenetic stage characterized by a wide range of porosity which decreases with depth, and thermal maturation which increases with depth (from immature up to the oil window). As confirmation of the method, the levels of organic content and maturity were confirmed using Rock-Eval pyrolysis data. Following the RP analysis, horizontal (HTI) and vertical (VTI) S-wave velocity anisotropy were analyzed using cross-dipole shear well logs (based on Stoneley waves response). It was found that anisotropy, in addition to the RP analysis, can assist in delineating the organic-rich sections, microfractures, and changes in gas saturation due to thermal maturation. Specifically, increasing thermal maturation enhances VTI and azimuthal HTI S-wave velocity anisotropies, in the ductile and brittle sections, respectively. The observed relationships are quite robust based on the high-quality laboratory and log data. However, our conclusions may be limited to the early stages of maturation and burial diagenesis, as at higher maturation and diagenesis the changes in physical properties can vary significantly.

Application of structural interpretation and simultaneous inversion to reservoir characterization of the Duvernay Formation, Fox Creek, Alberta, Canada

2019 ◽  
Vol 38 (2) ◽  
pp. 151-160 ◽  
Author(s):  
Ronald Weir ◽  
Don Lawton ◽  
Laurence Lines ◽  
Thomas Eyre ◽  
David Eaton
Keyword(s):  
Reservoir Characterization ◽  
Lateral Displacement ◽  
Rock Properties ◽  
S Wave ◽  
Amplitude Variation With Offset ◽  
Structural Interpretation ◽  
Simultaneous Inversion ◽  
Prestack Inversion ◽  
Unconventional Resource ◽  
Depth Relationship

Simultaneous prestack inversion of multicomponent 3D seismic data integrated with structural interpretation can provide an effective workflow to maximize value for unconventional plays. We outline an integrated workflow for characterizing the Duvernay play in western Canada, an emerging world-class low-permeability unconventional resource fairway. This workflow includes the determination of a time-depth relationship using synthetic seismograms, generation of seismic-derived time- and depth-converted structural maps, and calculation of inversion-based parameters of density and P- and S-wave velocity. The model-based procedure includes poststack (acoustic) inversion, amplitude variation with offset prestack inversion, and joint PP-PS inversion. With these rock properties determined, calculations are made to determine Young's modulus, Poisson's ratio, and brittleness. Faults are mapped based on time slices, isochrons, and correlatable vertical displacements of stratigraphic marker reflections. Significant strike-slip movements are identified by lateral displacement on interpreted geologic features, such as channels and reef edges. Seismic-derived attributes, combined with structural mapping, highlight zones that are conducive to hydraulic fracturing as well as areas unfavorable for development. Mapping of structural discontinuities provides a framework for understanding zones of preexisting weakness and induced-seismicity hazards.

Useful approximations for converted‐wave AVO

Geophysics ◽  
2001 ◽  
Vol 66 (6) ◽  
pp. 1721-1734 ◽  
Author(s):  
Antonio C. B. Ramos ◽  
John P. Castagna
Keyword(s):  
Wave Velocity ◽  
Random Noise ◽  
P Wave ◽  
Rock Properties ◽  
Negative Slope ◽  
High Contrast ◽  
Fractional Change ◽  
S Wave ◽  
Converted Wave ◽  
Low Contrast

Converted‐wave amplitude versus offset (AVO) behavior may be fit with a cubic relationship between reflection coefficient and ray parameter. Attributes extracted using this form can be directly related to elastic parameters with low‐contrast or high‐contrast approximations to the Zoeppritz equations. The high‐contrast approximation has the advantage of greater accuracy; the low‐contrast approximation is analytically simpler. The two coefficients of the low‐contrast approximation are a function of the average ratio of compressional‐to‐shear‐wave velocity (α/β) and the fractional changes in S‐wave velocity and density (Δβ/β and Δρ/ρ). Because of its simplicity, the low‐contrast approximation is subject to errors, particularly for large positive contrasts in P‐wave velocity associated with negative contrasts in S‐wave velocity. However, for incidence angles up to 40° and models confined to |Δβ/β| < 0.25, the errors in both coefficients are relatively small. Converted‐wave AVO crossplotting of the coefficients of the low‐contrast approximation is a useful interpretation technique. The background trend in this case has a negative slope and an intercept proportional to the α/β ratio and the fractional change in S‐wave velocity. For constant α/β ratio, an attribute trace formed by the weighted sum of the coefficients of the low‐contrast approximation provides useful estimates of the fractional change in S‐wave velocity and density. Using synthetic examples, we investigate the sensitivity of these parameters to random noise. Integrated P‐wave and converted‐wave analysis may improve estimation of rock properties by combining extracted attributes to yield fractional contrasts in P‐wave and S‐wave velocities and density. Together, these parameters may provide improved direct hydrocarbon indication and can potentially be used to identify anomalies caused by low gas saturations.

scholarly journals On the Effect of CO2 on Seismic and Ultrasonic Properties: A Novel Shale Experiment

Energies ◽  
2021 ◽  
Vol 14 (16) ◽  
pp. 5007
Author(s):  
Stian Rørheim ◽  
Mohammad Hossain Bhuiyan ◽  
Andreas Bauer ◽  
Pierre Rolf Cerasi
Keyword(s):  
Young’S Modulus ◽  
Wave Velocity ◽  
Poisson’S Ratio ◽  
Young's Modulus ◽  
Co2 Storage ◽  
Poisson's Ratio ◽  
Rock Properties ◽  
S Wave ◽  
Velocity Changes ◽  
4D Seismic

Carbon capture and storage (CCS) by geological sequestration comprises a permeable formation (reservoir) for CO2 storage topped by an impermeable formation (caprock). Time-lapse (4D) seismic is used to map CO2 movement in the subsurface: CO2 migration into the caprock might change its properties and thus impact its integrity. Simultaneous forced-oscillation and pulse-transmission measurements are combined to quantify Young’s modulus and Poisson’s ratio as well as P- and S-wave velocity changes in the absence and in the presence of CO2 at constant seismic and ultrasonic frequencies. This combination is the laboratory proxy to 4D seismic because rock properties are monitored over time. It also improves the understanding of frequency-dependent (dispersive) properties needed for comparing in-situ and laboratory measurements. To verify our method, Draupne Shale is monitored during three consecutive fluid exposure phases. This shale appears to be resilient to CO2 exposure as its integrity is neither compromised by notable Young’s modulus and Poisson’s ratio nor P- and S-wave velocity changes. No significant changes in Young’s modulus and Poisson’s ratio seismic dispersion are observed. This absence of notable changes in rock properties is attributed to Draupne being a calcite-poor shale resilient to acidic CO2-bearing brine that may be a suitable candidate for CCS.

Converted-wave model building and imaging based on common-focus-point methodology

Geophysics ◽  
2020 ◽  
Vol 85 (6) ◽  
pp. U139-U149
Author(s):  
Hongwei Liu ◽  
Mustafa Naser Al-Ali ◽  
Yi Luo
Keyword(s):  
Elastic Wave ◽  
Wave Velocity ◽  
Seismic Data ◽  
Model Building ◽  
P Wave ◽  
Rock Properties ◽  
S Wave ◽  
Converted Wave ◽  
Seismic Images ◽  
Focus Point

Seismic images can be viewed as photographs for underground rocks. These images can be generated from different reflections of elastic waves with different rock properties. Although the dominant seismic data processing is still based on the acoustic wave assumption, elastic wave processing and imaging have become increasingly popular in recent years. A major challenge in elastic wave processing is shear-wave (S-wave) velocity model building. For this reason, we have developed a sequence of procedures for estimating seismic S-wave velocities and the subsequent generation of seismic images using converted waves. We have two main essential new supporting techniques. The first technique is the decoupling of the S-wave information by generating common-focus-point gathers via application of the compressional-wave (P-wave) velocity on the converted seismic data. The second technique is to assume one common VP/ VS ratio to approximate two types of ratios, namely, the ratio of the average earth layer velocity and the ratio of the stacking velocity. The benefit is that we reduce two unknown ratios into one, so it can be easily scanned and picked in practice. The PS-wave images produced by this technology could be aligned with the PP-wave images such that both can be produced in the same coordinate system. The registration between the PP and PS images provides cross-validation of the migrated structures and a better estimation of underground rock and fluid properties. The S-wave velocity, computed from the picked optimal ratio, can be used not only for generating the PS-wave images, but also to ensure well registration between the converted-wave and P-wave images.

Fracture-porosity inversion from P-wave AVOA data along 2D seismic lines: An example from the Austin Chalk of southeast Texas

Geophysics ◽  
2007 ◽  
Vol 72 (1) ◽  
pp. B1-B7 ◽  
Author(s):  
Abdullatif A. Al-Shuhail
Keyword(s):  
Aspect Ratio ◽  
Wave Velocity ◽  
P Wave ◽  
S Wave ◽  
Amplitude Variation ◽  
Fracture Porosity ◽  
Amplitude Variation With Offset ◽  
P Wave Velocity ◽  
Austin Chalk ◽  
Southeast Texas

Vertical aligned fractures can significantly enhance the horizontal permeability of a tight reservoir. Therefore, it is important to know the fracture porosity and direction in order to develop the reservoir efficiently. P-wave AVOA (amplitude variation with offset and azimuth) can be used to determine these fracture parameters. In this study, I present a method for inverting the fracture porosity from 2D P-wave seismic data. The method is based on a modeling result that shows that the anisotropic AVO (amplitude variation with offset) gradient is negative and linearly dependent on the fracture porosity in a gas-saturated reservoir, whereas the gradient is positive and linearly dependent on the fracture porosity in a liquid-saturated reservoir. This assumption is accurate as long as the crack aspect ratio is less than 0.1 and the ratio of the P-wave velocity to the S-wave velocity is greater than 1.8 — two conditions that are satisfied in most naturally fractured reservoirs. The inversion then uses the fracture strike, the crack aspect ratio, and the ratio of the P-wave velocity to the S-wave velocity to invert the fracture porosity from the anisotropic AVO gradient after inferring the fluid type from the sign of the anisotropic AVO gradient. When I applied this method to a seismic line from the oil-saturated zone of the fractured Austin Chalk of southeast Texas, I found that the inversion gave a median fracture porosity of 0.21%, which is within the fracture-porosity range commonly measured in cores from the Austin Chalk.

Wavefield and AVO modeling using elastic thin-slab method

Geophysics ◽  
2006 ◽  
Vol 71 (5) ◽  
pp. C57-C67 ◽  
Author(s):  
Xian-Yun Wu ◽  
Ru-Shan Wu
Keyword(s):  
Finite Difference ◽  
Wave Velocity ◽  
Finite Difference Methods ◽  
P Wave ◽  
Thin Slab ◽  
Slab Method ◽  
S Wave ◽  
Amplitude Variation With Offset ◽  
Local Variance ◽  
Parameter Perturbations

We propose a dual-domain, one-way, elastic thin-slab method for fast and accurate amplitude variation with offset (AVO) modeling. In this method, the wavefield propagates in the wavenumber domain and interacts with heterogeneity in the space domain. The approach requires much less memory and is two to three orders of magnitude faster than a full-wave method using finite difference or finite element. The thin-bed AVO and AVOs with lateral parameter variations have been conducted using the thin-slab method and compared with reflectivity and finite-difference methods, respectively. It is shown that the thin-slab method can be used to accurately model reflections for most sedimentary rocks that have intermediate parameter perturbations ([Formula: see text] for P-wave velocity and [Formula: see text] for S-wave velocity). The combined effects of overburden structure and the scattering associated with heterogeneities on AVO have been investigated using the thin-slab method. Properties of the target zone and overburden structure control the AVO trends at overall offsets. Scattering associated with heterogeneities increases local variance in the reflected amplitudes and becomes significant for the sedimentary models with weak reflections. Interpretation of AVO observations based on homogeneous elastic models would therefore bias the estimated properties of the target. Furthermore, these effects can produce different apparent AVO trends in different offset ranges.

Sediments with gas hydrates: Internal structure from seismic AVO

Geophysics ◽  
1998 ◽  
Vol 63 (5) ◽  
pp. 1659-1669 ◽  
Author(s):  
Christine Ecker ◽  
Jack Dvorkin ◽  
Amos Nur
Keyword(s):  
Internal Structure ◽  
Wave Velocity ◽  
Seismic Data ◽  
Pore Space ◽  
Rock Physics ◽  
P Wave ◽  
S Wave ◽  
High Concentration ◽  
Amplitude Variation With Offset ◽  
Bottom Simulating Reflector

We interpret amplitude variation with offset (AVO) data from a bottom simulating reflector (BSR) offshore Florida by using rock‐physics‐based synthetic seismic models. A previously conducted velocity and AVO analysis of the in‐situ seismic data showed that the BSR separates hydrate‐bearing sediments from sediments containing free methane. The amplitude at the BSR are increasingly negative with increasing offset. This behavior was explained by P-wave velocity above the BSR being larger than that below the BSR, and S-wave velocity above the BSR being smaller than that below the BSR. We use these AVO and velocity results to infer the internal structure of the hydrated sediment. To do so, we examine two micromechanical models that correspond to the two extreme cases of hydrate deposition in the pore space: (1) the hydrate cements grain contacts and strongly reinforces the sediment, and (2) the hydrate is located away from grain contacts and does not affect the stiffness of the sediment frame. Only the second model can qualitatively reproduce the observed AVO response. Thus inferred internal structure of the hydrate‐bearing sediment means that (1) the sediment above the BSR is uncemented and, thereby, mechanically weak, and (2) its permeability is very low because the hydrate clogs large pore‐space conduits. The latter explains why free gas is trapped underneath the BSR. The seismic data also indicate the absence of strong reflections at the top of the hydrate layer. This fact suggests that the high concentration of hydrates in the sediment just above the BSR gradually decreases with decreasing depth. This effect is consistent with the fact that the low‐permeability hydrated sediments above the BSR prevent free methane from migrating upwards.

Stratigraphy of the Lower Tertiary formations of Panjab Himalayas

1968 ◽  
Vol 105 (5) ◽  
pp. 421-430 ◽  
Author(s):  
R. S. Chaudhri
Keyword(s):  
North American ◽  
Upper Eocene ◽  
Lower Miocene ◽  
Lower Tertiary ◽  
Lower Oligocene ◽  
Upper Oligocene ◽  
Tertiary System

SUMMARYLower Tertiary rocks of the Panjab Himalayas are classified under the Lower Tertiary System which comprises the Subathu Series (Upper Palaeocene-Eocene), the Dagshai Series (Upper Eocene-Lower Oligocene) and the Kasauli Series (Upper Oligocene-Lower Miocene). There is perfect stratigraphic harmony between the Subathus and the Dagshais, and the latter, in turn, grade into the Kasauli Series.Correlation of the Lower Tertiary rocks of India, Pakistan and Burma and their European and North American equivalents is tabulated.

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