Estimation of microfracture porosity in deep carbonate reservoirs based on 3D rock-physics templates

2020 ◽  
Vol 8 (4) ◽  
pp. SP43-SP52
Author(s):  
Mengqiang Pang ◽  
Jing Ba ◽  
Li-Yun Fu ◽  
José M. Carcione ◽  
Uti I. Markus ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Velocity Ratio ◽  
Rock Physics ◽  
Total Porosity ◽  
Spectral Ratio ◽  
Wave Impedance ◽  
Seismic Attenuation ◽  
Carbonate Reservoirs ◽  
P Wave ◽  
Ratio Method

Carbonate reservoirs in the S area of the Tarim Basin (China) are ultradeep hydrocarbon resources, with low porosity, complex fracture systems, and dissolved pores. Microfracturing is a key factor of reservoir connectivity and storage space. We have performed measurements on limestone samples, under different confining pressures, and we used the self-consistent approximation model and the Biot-Rayleigh theory of double porosity to study the microfractures. We have computed the fluid properties (mainly oil) as a function of temperature and pressure. Using the dependence of seismic [Formula: see text] on the microfractures, a multiscale 3D rock-physics template (RPT) is built, based on the attenuation, P-wave impedance, and phase velocity ratio. We estimate the ultrasonic and seismic attenuation with the spectral-ratio method and the improved frequency-shift method, respectively. Then, calibration of the RPTs is performed at ultrasonic and seismic frequencies. We use the RPTs to estimate the total and microfracture porosities. The results indicate that the total porosity is low and the microfracture porosity is relatively high, which is consistent with the well log data and actual oil production reports. This work presents a method for identification of deep carbonate reservoirs by using the microfracture porosity estimated from the 3D RPT, which could be exploited in oil and gas exploration.

Temperature, differential-pressure and porosity inversion for ultra-deep carbonate reservoirs based on 3D rock physics templates

Geophysics ◽  
2021 ◽  
pp. 1-54
Author(s):  
Yijun Wei ◽  
Jing Ba ◽  
José M. Carcione ◽  
Li-Yun Fu ◽  
Mengqiang Pang ◽  
...  
Keyword(s):  
Signal To Noise Ratio ◽  
Rock Physics ◽  
Wave Impedance ◽  
Tectonic Stress ◽  
Differential Pressure ◽  
Carbonate Reservoirs ◽  
Hydrocarbon Exploration ◽  
P Wave ◽  
High Porosity ◽  
Temperature Differential

Ultra-deep carbonate reservoirs have high temperatures and pressures, complex pressure/tectonic stress settings and pore structures. These conditions make their seismic detection and characterization difficult, particularly if the signal-to-noise ratio is low, as it is the case in most situations. Moreover, the high risk of deep-drilling exploration makes it impractical to carry out normal logging operations. We propose a temperature-differential pressure-porosity (TPP) rock-physics model based on the Biot-Rayleigh poroelasticity theory to describe the wave response of the reservoir. A preliminary analysis shows that temperature, pressure and porosity are well correlated with wave velocity and attenuation. On the basis of this theory, we built 3D rock-physics templates that account for the effects of TPP on the P-wave impedance, VP/ VS ratio and attenuation. The templates are calibrated with laboratory, well-log and seismic data of the S area (Shuntuoguole uplift, Tarim Basin, Xinjiang, China). Then, the template is used to obtain the properties of the reservoir at seismic frequencies. The predicted results are consistent with the field reports, high temperature, low differential pressure and high porosity, indicating high production rates. The methodology will be useful for the hydrocarbon exploration in ultra-deep carbonate reservoirs.

Basin-wide rock-physics analysis in Campeche Basin, Gulf of Mexico — Phase II: Reservoir rock and fluid properties

2021 ◽  
Vol 40 (10) ◽  
pp. 716-722
Author(s):  
Yangjun (Kevin) Liu ◽  
Michelle Ellis ◽  
Mohamed El-Toukhy ◽  
Jonathan Hernandez
Keyword(s):  
Oil And Gas ◽  
Rock Physics ◽  
Clay Content ◽  
American Petroleum Institute ◽  
P Wave ◽  
Reservoir Rock ◽  
Gas Oil ◽  
Amplitude Variation With Offset ◽  
Fluid Properties ◽  
The Impact

We present a basin-wide rock-physics analysis of reservoir rocks and fluid properties in Campeche Basin. Reservoir data from discovery wells are analyzed in terms of their relationship between P-wave velocity, density, porosity, clay content, Poisson's ratio (PR), and P-impedance (IP). The fluid properties are computed by using in-situ pressure, temperature, American Petroleum Institute gravity, gas-oil ratio, and volume of gas, oil, and water. Oil- and gas-saturated reservoir sands show strong PR anomalies compared to modeled water sand at equivalent depth. This suggests that PR anomalies can be used as a direct hydrocarbon indicator in the Tertiary sands in Campeche Basin. However, false PR anomalies due to residual gas or oil exist and compose about 30% of the total anomalies. The impact of fluid properties on IP and PR is calibrated using more than 30 discovery wells. These calibrated relationships between fluid properties and PR can be used to guide or constrain amplitude variation with offset inversion for better pore fluid discrimination.

Convolutional neural network for seismic impedance inversion

Geophysics ◽  
2019 ◽  
Vol 84 (6) ◽  
pp. R869-R880 ◽  
Author(s):  
Vishal Das ◽  
Ahinoam Pollack ◽  
Uri Wollner ◽  
Tapan Mukerji
Keyword(s):  
Rock Physics ◽  
Normal Incidence ◽  
Wave Impedance ◽  
Training Data ◽  
P Wave ◽  
Computation Method ◽  
Elastic Model ◽  
Spatial Correlations ◽  
Data Set ◽  
Earth Models

We have addressed the geophysical problem of obtaining an elastic model of the subsurface from recorded normal-incidence seismic data using convolutional neural networks (CNNs). We train the network on synthetic full-waveform seismograms generated using Kennett’s reflectivity method on earth models that were created under rock-physics modeling constraints. We use an approximate Bayesian computation method to estimate the posterior distribution corresponding to the CNN prediction and to quantify the uncertainty related to the predictions. In addition, we test the robustness of the network in predicting impedances of previously unobserved earth models when the input to the network consisted of seismograms generated using: (1) earth models with different spatial correlations (i.e. variograms), (2) earth models with different facies proportions, (3) earth models with different underlying rock-physics relations, and (4) source-wavelet phase and frequency different than in the training data. Results indicate that the predictions of the trained network are susceptible to facies proportions, the rock-physics model, and source-wavelet parameters used in the training data set. Finally, we apply CNN inversion on the Volve field data set from offshore Norway. P-wave impedance [Formula: see text] inverted for the Volve data set using CNN showed a strong correlation (82%) with the [Formula: see text] log at a well.

Évaluation du facteur de qualité sismique au barrage de Carillon (Québec)

2001 ◽  
Vol 28 (3) ◽  
pp. 496-508
Author(s):  
B Giroux ◽  
M Chouteau ◽  
L Laverdure
Keyword(s):  
Survey Design ◽  
Spectral Ratio ◽  
Microseismic Monitoring ◽  
Seismic Attenuation ◽  
P Wave ◽  
Q Value ◽  
A Value ◽  
P Wave Velocity ◽  
Aggregate Composition

The seismic attenuation in concrete has seldom been studied, although it is an important parameter for survey design. In this paper, the seismic Q factor is estimated from data measured at the Carillon dam. Three methods were used for this study: amplitude decay yielding a value of 5.1 ± 1.6, spectral ratio giving a value of 8.3 ± 3.5, and a value of 7.5 ± 14.9 was obtained from the rise-time technique. These values are weak compared with what is generally observed in rocks, and slightly lower than values obtained on laboratory concrete samples. However, the average P wave velocity measured on the investigated area is 4081 ± 95 m·s–1, an indication of the good quality of the material. Consequently, this strong attenuation could be attributed on one hand to energy loss, and on the other hand to scattering caused by the intrinsic cement–aggregate composition of concrete. It is also possible that an inadequate sensor coupling had the effect of reducing the observed Q value. Key words: seismic attenuation, concrete dams, microseismic monitoring, coupling.

scholarly journals Microcrack Porosity Estimation Based on Rock Physics Templates: A Case Study in Sichuan Basin, China

Energies ◽  
2021 ◽  
Vol 14 (21) ◽  
pp. 7225
Author(s):  
Chuantong Ruan ◽  
Jing Ba ◽  
José M. Carcione ◽  
Tiansheng Chen ◽  
Runfa He
Keyword(s):  
Sichuan Basin ◽  
Rock Physics ◽  
Wave Impedance ◽  
Gas Production ◽  
P Wave ◽  
Gas Reservoirs ◽  
Tight Sandstone ◽  
Amplitude Variation With Offset ◽  
Xujiahe Formation ◽  
Seismic Properties

Low porosity-permeability structures and microcracks, where gas is produced, are the main characteristics of tight sandstone gas reservoirs in the Sichuan Basin, China. In this work, an analysis of amplitude variation with offset (AVO) is performed. Based on the experimental and log data, sensitivity analysis is performed to sort out the rock physics attributes sensitive to microcrack and total porosities. The Biot–Rayleigh poroelasticity theory describes the complexity of the rock and yields the seismic properties, such as Poisson’s ratio and P-wave impedance, which are used to build rock-physics templates calibrated with ultrasonic data at varying effective pressures. The templates are then applied to seismic data of the Xujiahe formation to estimate the total and microcrack porosities, indicating that the results are consistent with actual gas production reports.

Rock property- and seismic-attribute analysis of a chert reservoir in the Devonian Thirty-one Formation, west Texas, U.S.A.

Geophysics ◽  
2006 ◽  
Vol 71 (5) ◽  
pp. B151-B158 ◽  
Author(s):  
Dongjun (Taller) Fu ◽  
E. Charlotte Sullivan ◽  
Kurt J. Marfurt
Keyword(s):  
Rock Physics ◽  
Wave Impedance ◽  
Seismic Inversion ◽  
P Wave ◽  
Seismic Attribute ◽  
West Texas ◽  
Attribute Analysis ◽  
Bedded Chert ◽  
Petrophysical Logs ◽  
Tripolitic Chert

In west Texas, fractured-chert reservoirs of Devonian age have produced more than 700 million barrels of oil. About the same amount of mobile petroleum remains in place. These reservoirs are characterized by microporosity; they are heterogeneous and compartmented, which results in recovery of less than 30% of the oil in place. In this case study the objective was to use cores, petrophysical logs, rock physics, and seismic attributes to characterize porosity and field-scale fractures. The relations among porosity, velocity, and impedance were explored and also reactions among production, impedance, and lineaments observed in 3D attribute volumes. Laboratory core data show that Gassmann’s fluid-substitution equation works well for microporous tripolitic chert. Also, laboratry measurements show excellent linear correlation between P-wave impedance and porosity. Volumetric calculations of reflector curvature and seismic inversion of acoustic impedance were combined to infer distribution of lithofacies and fractures and to predict porosity. Statistical relations were established between P-wave velocity and porosity measured from cores, between P-wave impedance and producing zones, and between initial production rates and seismic “fracture lineaments.” The strong quantitative correlation between thick-bedded chert lithofacies and seismic impedance was used to map the reservoir. A qualitative inverse relation between the first [Formula: see text] of production and curvature lineaments was documented.

scholarly journals Fluid Discrimination in Ultra-Deep Reservoirs Based on a Double Double-Porosity Theory

2021 ◽  
Vol 9 ◽  
Author(s):  
Xinyang Zhou ◽  
Jing Ba ◽  
Juan E. Santos ◽  
José M. Carcione ◽  
Li-Yun Fu ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Wave Attenuation ◽  
Poisson Ratio ◽  
Mass Density ◽  
Rock Physics ◽  
Spectral Ratio ◽  
Double Porosity ◽  
P Wave ◽  
Oil Saturation ◽  
Frequency Bands

We develop a methodology, based on rock-physics templates, to effectively identify reservoir fluids in ultra-deep reservoirs, where the poroelasticity model is based on the double double-porosity theory. P-wave attenuation, the ratio of the first Lamé constant to mass density (λ/ρ) and Poisson ratio are used to build the templates at the ultrasonic and seismic frequency bands to quantitatively predict the total and crack (soft) porosities and oil saturation. Attenuation on these frequency bands is estimated with the spectral-ratio and frequency-shift methods. We apply the methodology to fault-controlled karst reservoirs in the Tarim Basin (China), which contain ultra-deep hydrocarbon resources with a diverse pore-crack system, low porosity/permeability and complex oil-water spatial distributions. The results are consistent with well-log data and actual oil recovery. Crack porosity can be used as an indicator to find regions with high oil saturation, since high values implies a good pore connectivity.

HOW GAS HYDRATE SATURATION AND MORPHOLOGY CONTROL SEISMIC ATTENUATION: A CASE STUDY FROM THE SOUTH HYDRATE RIDGE

2021 ◽  
pp. 1-63
Author(s):  
Aoshuang Ji ◽  
Tieyuan Zhu ◽  
Hector Marin-Moreno ◽  
Xiong Lei
Keyword(s):  
Gas Hydrate ◽  
Wave Attenuation ◽  
Rock Physics ◽  
Seismic Profile ◽  
Seismic Attenuation ◽  
P Wave ◽  
Frequency Range ◽  
The South ◽  
Hydrate Ridge ◽  
Hydrate Saturation

Prior studies have shown an ambiguous relationship between gas hydrate saturation and seismic attenuation in different regions, but the effect of gas hydrate morphology on seismic attenuation of hydrate-bearing sediments was often overlooked. Here we combine seismic data with rock physics modeling to elucidate how gas hydrate saturation and morphology may control seismic attenuation. To extract P-wave attenuation, we process both the vertical seismic profile (VSP) data within a frequency range of 30 – 150 Hz and sonic logging data within 10 – 15 kHz from three wells in the south Hydrate Ridge, offshore of Oregon (USA), collected during Ocean Drilling Program (ODP) Leg 204 in 2000. We calculate P-wave attenuation using spectral matching and centroid frequency shift methods, and use Archie's relationship to derive gas hydrate saturation from the resistivity data above the bottom simulating reflection (BSR) at the same wells. To interpret observed seismic attenuation in terms of the effects of both gas hydrate saturation and morphology, we employ the Hydrate-Bearing Effective Sediment (HBES) rock physics model. By comparing the observed and model-predicted attenuation values, we infer that: (1) seismic attenuation appears to not be dominated by any single factor, instead, its variation is likely governed by both gas hydrate saturation and morphology; (2) the relationship between seismic attenuation and gas hydrate saturation varies with different hydrate morphologies; (3) the squirt flow, occurring at different compliances of adjacent pores driven by pressure gradients, may be responsible for the significantly large or small attenuation over a broad frequency range.

Estimating attenuation and the relative information content of amplitude and phase spectra

Geophysics ◽  
2007 ◽  
Vol 72 (1) ◽  
pp. R19-R27 ◽  
Author(s):  
James Rickett
Keyword(s):  
Phase Difference ◽  
Seismic Waves ◽  
Spectral Ratio ◽  
Seismic Attenuation ◽  
Ratio Method ◽  
Relative Uncertainty ◽  
Phase Information ◽  
Relative Information ◽  
The Difference ◽  
Phase Spectra

Seismic attenuation affects both the amplitude and phase of seismic waves. Algorithms to estimate attenuation are split among those that use amplitude information (e.g., spectral-ratio method), those that use phase information (e.g., rise-time method), and those that use a combination of both (e.g., time-domain algorithms). In this study, I explore the relative information provided by amplitude and phase spectra. To do this, I show how the difference in phase spectra between waveforms recorded at two depth levels can be used to estimate attenuation. This phase-difference method is analogous to the method of spectral ratios, but uses phase information rather than amplitude information. Under the simplifying assumption that the noise in both log-amplitude and phase spectra can be modeled as uncorrelated Gaussian random variables with equal variance, the posterior variances in the attenuation estimates from the spectral-ratio and phase-difference methods can be compared directly. It turns out that over typical seismic bandwidths and typical levels of attenuation, the relative uncertainty in estimates of attenuation from phase spectra is approximately twice the relative uncertainty in estimates of attenuation from log-amplitude spectra. Including phase and amplitude information simultaneously (as opposed to just amplitude information) reduces the relative uncertainty by only about 10% over seismic bandwidths. This reduction in uncertainty is not large, but may be significant depending on the sensitivity of the application.

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