scholarly journals Estimation of elastic moduli of mixed porous clay composites

Geophysics ◽  
2011 ◽  
Vol 76 (1) ◽  
pp. E9-E20 ◽  
Author(s):  
Erling Hugo Jensen ◽  
Charlotte Faust Andersen ◽  
Tor Arne Johansen
Keyword(s):  
Experimental Data ◽  
Elastic Properties ◽  
Elastic Moduli ◽  
Rock Physics ◽  
Common Procedure ◽  
Effective Elastic Properties ◽  
Confining Pressures ◽  
Physics Model ◽  
Rock Physics Model ◽  
The Individual

We have developed a procedure for estimating the effective elastic properties of various mixtures of smectite and kaolinite over a range of confining pressures, based on the individual effective elastic properties of pure porous smectite and kaolinite. Experimental data for the pure samples are used as input to various rock physics models, and the predictions are compared with experimental data for the mixed samples. We have evaluated three strategies for choosing the initial properties in various rock physics models: (1) input values have the same porosity, (2) input values have the same pressure, and (3) an average of (1) and (2). The best results are obtained when the elastic moduli of the two porous constituents are defined at the same pressure and when their volumetric fractions are adjusted based on different compaction rates with pressure. Furthermore, our strategy makes the modeling results less sensitive to the actual rock physics model. The method can help obtain the elastic properties of mixed unconsolidated clays as a function of mechanical compaction. The more common procedure for estimating effective elastic properties requires knowledge about volume fractions, elastic properties of individual constituents, and geometric details of the composition. However, these data are often uncertain, e.g., large variations in the mineral elastic properties of clays have been reported in the literature, which makes our procedure a viable alternative.

Elastic mineral facies: Selecting site-specific elastic moduli of clay

Geophysics ◽  
2017 ◽  
Vol 82 (4) ◽  
pp. MR111-MR119
Author(s):  
Uri Wollner ◽  
Jack P. Dvorkin
Keyword(s):  
Elastic Moduli ◽  
Rock Physics ◽  
Data Sets ◽  
Depth Range ◽  
Chemical Formula ◽  
Rock Matrix ◽  
Well Control ◽  
Physics Model ◽  
Well Data ◽  
Rock Physics Model

The elastic moduli of the mineral constituents of the rock matrix are among the principal inputs in all rock-physics velocity-porosity-mineralogy models. Published experimental data indicate that the elastic moduli for essentially any mineral vary. The ranges of these variations are especially wide for clay. The question addressed here is how to select, based on well data, concrete values for clay’s elastic constants where those for other minerals are fixed. The approach is to find a rock-physics model for zero-clay intervals and then adjust the clay’s constants to describe the intervals dominated by clay using the same model. We examine three data sets from clastic environments, each represented by three wells, where the selected constants for clay were different between the fields but stable within each field. These constants can then be used for seismic forward modeling and interpretation in a specific field away from well control and within a depth range represented in the wells. In essence, we introduce the concept of elastic mineral facies where we identify clay as a mineral with certain elastic moduli rather than by its chemical formula.

scholarly journals A rock physics model for the characterization of organic-rich shale from elastic properties

2015 ◽  
Vol 12 (2) ◽  
pp. 264-272 ◽  
Author(s):  
Ying Li ◽  
Zhi-Qi Guo ◽  
Cai Liu ◽  
Xiang-Yang Li ◽  
Gang Wang
Keyword(s):  
Elastic Properties ◽  
Rock Physics ◽  
Physics Model ◽  
Rock Physics Model

Seismic-scale dependence of the effective bulk modulus of pore fluid upon water saturation

Geophysics ◽  
2018 ◽  
Vol 83 (2) ◽  
pp. MR81-MR91 ◽  
Author(s):  
Uri Wollner ◽  
Jack Dvorkin
Keyword(s):  
Bulk Modulus ◽  
Water Saturation ◽  
Rock Physics ◽  
Clay Content ◽  
Pore Fluid ◽  
Arithmetic Average ◽  
Physics Model ◽  
Rock Physics Model ◽  
The Individual ◽  
Seismic Scale

We apply a rock-physics model established from fine-scale data (well or laboratory) to the seismically derived elastic variables (the impedances and bulk density) to arrive at the seismic-scale total porosity, clay content, and water saturation. These three outputs are defined as the volume-averaged porosity, clay content, and porosity-weighted water saturation, respectively. To use the rock-physics model, we need to know how to relate the bulk modulus of the pore fluid to water saturation in the presence of hydrocarbons. At the wellbore-measurement scale, this relation is typically the saturation-weighted harmonic average of the bulk moduli of the water and hydrocarbon. The question posed here is what this relation is at the seismic scale. The method of solution is based on the wellbore-scale data. Specifically, we seek the seismic-scale bulk modulus of the pore fluid that, if used in the rock-physics model, will yield the Backus-upscaled elastic constants at the well from the above-defined seismic-scale petrophysical variables. The answer depends on the vertical distribution of all these variables. By using examples of synthetic and real wells and assuming the lack of hydraulic communication between adjacent rock bodies, we find that this relation trends toward the arithmetic average of the individual bulk moduli of the pore-fluid phases. In fact, it falls in between the arithmetic average and the linear combination of 0.75 arithmetic and 0.25 harmonic averages. We also develop an approximate analytical solution under the assumption of weak elastic and porosity contrasts and for medium-to-high porosity sediment that indicates that the seismic-scale bulk modulus of the pore fluid is close to the arithmetic average of those in the individual layers.

Elastic properties of heavy oil sands: Effects of temperature, pressure, and microstructure

Geophysics ◽  
2016 ◽  
Vol 81 (4) ◽  
pp. D453-D464 ◽  
Author(s):  
Hui Li ◽  
Luanxiao Zhao ◽  
De-Hua Han ◽  
Min Sun ◽  
Yu Zhang
Keyword(s):  
Elastic Properties ◽  
Heavy Oil ◽  
Oil Sands ◽  
Rock Physics ◽  
Solid Matrix ◽  
Sand Sample ◽  
Oil Sand ◽  
Glass Point ◽  
Physics Model ◽  
Rock Physics Model

We have investigated the elastic properties of heavy oil sands influenced by the multiphase properties of heavy oil itself and the solid matrix with regard to temperature, pressure, and microstructure. To separately identify the role of the heavy oil and solid matrix under specific conditions, we have designed and performed special ultrasonic measurements for the heavy oil and heavy oil-saturated solids artificial samples. The measured data indicate that the viscosity of heavy oil reaches [Formula: see text] at the temperature of glass point, leading the heavy oil to act as a part of a solid frame of the heavy oil sand sample. The heavy oil is likely movable pore fluid accordingly once its viscosity dramatically drops to approximately [Formula: see text] at the temperature of liquid point. The viscosity-induced elastic modulus of heavy oil in turn makes the elastic properties of heavy oil-saturated grain solid sample to be temperature dependent. In addition, the rock physics model suggests that the microstructure of heavy oil sand is transitional; consequently, the solid Gassmann equation underestimates the measured velocities at the low temperature range of the quasisolid phase of heavy oil, whereas overestimates when the temperature exceeds the liquid point. The heavy oil sand sample has a higher modulus and approaches the upper bound due to the stiffer heavy oil itself acting as a rock frame as the temperature decreases. In contrary, heavy oil sand displays a lower modulus and approaches the lower bound when the heavy oil becomes softer as the temperature goes up.

Rock-physics transforms and scale of investigation

Geophysics ◽  
2017 ◽  
Vol 82 (3) ◽  
pp. MR75-MR88 ◽  
Author(s):  
Jack Dvorkin ◽  
Uri Wollner
Keyword(s):  
Elastic Properties ◽  
Rock Physics ◽  
Clay Content ◽  
Pore Fluid ◽  
Petrophysical Properties ◽  
Reflection Seismology ◽  
Physics Model ◽  
Well Data ◽  
Rock Physics Model ◽  
Seismic Scale

Rock-physics “velocity-porosity” transforms are usually established on sets of laboratory and/or well data with the latter data source being dominant in recent practice. The purpose of establishing such transforms is to (1) conduct forward modeling of the seismic response for various geologically plausible “what if” scenarios in the subsurface and (2) interpret seismic data for petrophysical properties and conditions, such as porosity, clay content, and pore fluid. Because the scale of investigation in the well is considerably smaller than that in reflection seismology, an important question is whether the rock-physics model established in the well can be used at the seismic scale. We use synthetic examples and well data to show that a rock-physics model established at the well approximately holds at the seismic scale, suggest a reason for this scale independence, and explore where it may be violated. The same question can be addressed as an inverse problem: Assume that we have a rock-physics transform and know that it works at the scale of investigation at which the elastic properties are seismically measured. What are the upscaled (smeared) petrophysical properties and conditions that these elastic properties point to? It appears that they are approximately the arithmetically volume-averaged porosity and clay content (in a simple quartz/clay setting) and are close to the arithmetically volume-averaged bulk modulus of the pore fluid (rather than averaged saturation).

scholarly journals Velocity-Porosity-Mineralogy Model for Unconventional Shale and Its Applications to Digital Rock Physics

2021 ◽  
Vol 8 ◽  
Author(s):  
Jack Dvorkin ◽  
Joel Walls ◽  
Gabriela Davalos
Keyword(s):  
Elastic Wave ◽  
Elastic Properties ◽  
Wave Velocity ◽  
Solid Phase ◽  
Rock Physics ◽  
Elastic Wave Velocity ◽  
Mathematical Form ◽  
Critical Porosity ◽  
Physics Model ◽  
Rock Physics Model

By examining wireline data from Woodford and Wolfcamp gas shale, we find that the primary controls on the elastic-wave velocity are the total porosity, kerogen content, and mineralogy. At a fixed porosity, both Vp and Vs strongly depend on the clay content, as well as on the kerogen content. Both velocities are also strong functions of the sum of the above two components. Even better discrimination of the elastic properties at a fixed porosity is attained if we use the elastic-wave velocity of the solid matrix (including kerogen) of rock as the third variable. This finding, fairly obvious in retrospect, helps combine all mineralogical factors into only two variables, Vp and Vs of the solid phase. The constant-cement rock physics model, whose mathematical form is the modified lower Hashin-Shtrikman elastic bound, accurately describes the data. The inputs to this model include the elastic moduli and density of the solid component (minerals plus kerogen), those of the formation fluid, the differential pressure, and the critical porosity and coordination number (the average number of grain-to-grain contacts at the critical porosity). We show how this rock physics model can be used to predict the elastic properties from digital images of core, as well as 2D scanning electron microscope images of very small rock fragments.

Using cuttings to extract geomechanical properties along lateral wells in unconventional reservoirs

Geophysics ◽  
2018 ◽  
Vol 83 (3) ◽  
pp. MR167-MR185 ◽  
Author(s):  
Romain Prioul ◽  
Richard Nolen-Hoeksema ◽  
MaryEllen Loan ◽  
Michael Herron ◽  
Ridvan Akkurt ◽  
...  
Keyword(s):  
Organic Matter ◽  
Elastic Moduli ◽  
Rock Physics ◽  
In Situ Stress ◽  
Vertical Control ◽  
Petrophysical Model ◽  
Minimum Stress ◽  
Physics Model ◽  
Rock Physics Model

We have developed a method using measurements on drill cuttings as well as calibrated models to estimate anisotropic mechanical properties and stresses in unconventional reservoirs, when logs are not available in lateral wells. We measured mineralogy and organic matter on cuttings using diffuse reflectance infrared Fourier transform spectroscopy (DRIFTS). We described the methodology and illustrated it using two vertical control wells in the Vaca Muerta Formation, Argentina, and one lateral well drilled in the low-maturity oil-bearing reservoir. The method has two steps. First, using a vertical control well containing measurements from cuttings, a comprehensive logging suite, cores, and in situ stress tests, we define and calibrate four models: petrophysical, rock physics, dynamic-static elastic, and geomechanical. The petrophysical model provides petrophysical constituent volumes (mineralogy, organic matter, and fluids) from logs or DRIFTS inputs to the rock-physics model for calculating the dynamic anisotropic elastic moduli. The dynamic-static elastic and geomechanics models provide the relationships for computing static elastic properties and the minimum stress. Second, we acquire DRIFTS data on cuttings in the target lateral well and apply the four models for calculating stresses. We find that the method is successful for two reasons. First, the sonic-log-derived elastic moduli could be reconstructed accurately from the rock-physics model using input from petrophysical volumes from logs and DRIFTS data. A striking observation is that the elastic-property heterogeneity in those wells is explainable almost solely by compositional variations. Second, petrophysical volumes can be reconstructed by the petrophysical model and DRIFTS data. In the lateral well, we observed horizontal variations of mineralogy and organic matter, which controlled variations of elastic moduli and its anisotropy, and, in turn, affected partitioning of the gravitational and tectonic components in the minimum stress. This methodology promises accurate in situ stress estimates using cutting-based measurements and assessments of unconventional-reservoir heterogeneity.

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