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

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.

Author(s):  
Yanxiang Yu ◽  
◽  
Chicheng Xu ◽  
Siddharth Misra ◽  
Weichang Li ◽  
...  

Compressional and shear sonic traveltime logs (DTC and DTS, respectively) are crucial for subsurface characterization and seismic-well tie. However, these two logs are often missing or incomplete in many oil and gas wells. Therefore, many petrophysical and geophysical workflows include sonic log synthetization or pseudo-log generation based on multivariate regression or rock physics relations. Started on March 1, 2020, and concluded on May 7, 2020, the SPWLA PDDA SIG hosted a contest aiming to predict the DTC and DTS logs from seven “easy-to-acquire” conventional logs using machine-learning methods (GitHub, 2020). In the contest, a total number of 20,525 data points with half-foot resolution from three wells was collected to train regression models using machine-learning techniques. Each data point had seven features, consisting of the conventional “easy-to-acquire” logs: caliper, neutron porosity, gamma ray (GR), deep resistivity, medium resistivity, photoelectric factor, and bulk density, respectively, as well as two sonic logs (DTC and DTS) as the target. The separate data set of 11,089 samples from a fourth well was then used as the blind test data set. The prediction performance of the model was evaluated using root mean square error (RMSE) as the metric, shown in the equation below: RMSE=sqrt(1/2*1/m* [∑_(i=1)^m▒〖(〖DTC〗_pred^i-〖DTC〗_true^i)〗^2 + 〖(〖DTS〗_pred^i-〖DTS〗_true^i)〗^2 ] In the benchmark model, (Yu et al., 2020), we used a Random Forest regressor and conducted minimal preprocessing to the training data set; an RMSE score of 17.93 was achieved on the test data set. The top five models from the contest, on average, beat the performance of our benchmark model by 27% in the RMSE score. In the paper, we will review these five solutions, including preprocess techniques and different machine-learning models, including neural network, long short-term memory (LSTM), and ensemble trees. We found that data cleaning and clustering were critical for improving the performance in all models.


Energies ◽  
2021 ◽  
Vol 14 (21) ◽  
pp. 7225
Author(s):  
Chuantong Ruan ◽  
Jing Ba ◽  
José M. Carcione ◽  
Tiansheng Chen ◽  
Runfa He

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.


Geophysics ◽  
2021 ◽  
pp. 1-54
Author(s):  
Yijun Wei ◽  
Jing Ba ◽  
José M. Carcione ◽  
Li-Yun Fu ◽  
Mengqiang Pang ◽  
...  

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.


Geophysics ◽  
2006 ◽  
Vol 71 (5) ◽  
pp. B151-B158 ◽  
Author(s):  
Dongjun (Taller) Fu ◽  
E. Charlotte Sullivan ◽  
Kurt J. Marfurt

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.


Geophysics ◽  
2001 ◽  
Vol 66 (4) ◽  
pp. 988-1001 ◽  
Author(s):  
T. Mukerji ◽  
A. Jørstad ◽  
P. Avseth ◽  
G. Mavko ◽  
J. R. Granli

Reliably predicting lithologic and saturation heterogeneities is one of the key problems in reservoir characterization. In this study, we show how statistical rock physics techniques combined with seismic information can be used to classify reservoir lithologies and pore fluids. One of the innovations was to use a seismic impedance attribute (related to the [Formula: see text] ratio) that incorporates far‐offset data, but at the same time can be practically obtained using normal incidence inversion algorithms. The methods were applied to a North Sea turbidite system. We incorporated well log measurements with calibration from core data to estimate the near‐offset and far‐offset reflectivity and impedance attributes. Multivariate probability distributions were estimated from the data to identify the attribute clusters and their separability for different facies and fluid saturations. A training data was set up using Monte Carlo simulations based on the well log—derived probability distributions. Fluid substitution by Gassmann’s equation was used to extend the training data, thus accounting for pore fluid conditions not encountered in the well. Seismic inversion of near‐offset and far‐offset stacks gave us two 3‐D cubes of impedance attributes in the interwell region. The near‐offset stack approximates a zero‐offset section, giving an estimate of the normal incidence acoustic impedance. The far offset stack gives an estimate of a [Formula: see text]‐related elastic impedance attribute that is equivalent to the acoustic impedance for non‐normal incidence. These impedance attributes obtained from seismic inversion were then used with the training probability distribution functions to predict the probability of occurrence of the different lithofacies in the interwell region. Statistical classification techniques, as well as geostatistical indicator simulations were applied on the 3‐D seismic data cube. A Markov‐Bayes technique was used to update the probabilities obtained from the seismic data by taking into account the spatial correlation as estimated from the facies indicator variograms. The final results are spatial 3‐D maps of not only the most likely facies and pore fluids, but also their occurrence probabilities. A key ingredient in this study was the exploitation of physically based seismic‐to‐reservoir property transforms optimally combined with statistical techniques.


Geophysics ◽  
2009 ◽  
Vol 74 (2) ◽  
pp. B37-B45 ◽  
Author(s):  
Abuduwali Aibaidula ◽  
George McMechan

Acoustic impedance inversion (AI) and simultaneous angle-dependent inversion (SADI) of a 3D seismic data set characterize reservoirs of Mississippian Morrowan age in the triangle zone of the frontal Ouachita Mountains, Oklahoma. Acoustic impedance of the near-angle seismic data images the 3D spatial distributions of Wapanucka limestone and Cromwell sandstone. Lamé [Formula: see text] ([Formula: see text] and [Formula: see text]) and [Formula: see text] sections are derived from the P-wave and S-wave impedance ([Formula: see text] and [Formula: see text]) sections produced by the SADI. Lithology is identified from the gamma logs and [Formula: see text]. The [Formula: see text], [Formula: see text], and [Formula: see text] are interpreted in terms of a hydrocarbon distribution pattern. The [Formula: see text] is used to identify high [Formula: see text] regions that are consistent with high sand/shale ratio. The estimated impedances and derived Lamé parameter sections are consistent with the interpretation that parts of the Wapanucka limestone and Cromwell sandstone contain potential gas reservoirs in fault-bounded compartments. The Cromwell sandstone contains the main inferred reservoirs; the two largest of these are each [Formula: see text] in pore volume. The inversion results also explain the observed low production in previous wells because those did not sample the best compartments. We propose a single new well location that would penetrate both reservoirs; 3D visualization facilitates this recommendation.


2020 ◽  
Vol 8 (4) ◽  
pp. SP43-SP52
Author(s):  
Mengqiang Pang ◽  
Jing Ba ◽  
Li-Yun Fu ◽  
José M. Carcione ◽  
Uti I. Markus ◽  
...  

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.


2015 ◽  
Vol 3 (1) ◽  
pp. SA15-SA31 ◽  
Author(s):  
Mark G. Kittridge

Using a variety of recent public-domain data sets comprising porosity, velocity (P- and S-waves), and, in most cases, mineralogy and petrographic data, I created an extensive global data set and evaluated the importance of mineralogy and pore type on the elastic properties behavior of carbonate core plugs. Results from this investigation clearly illuminated the potential for overinterpreting elastic properties behavior as a function of pore type(s) when mineralogy was not explicitly included in the analysis. Rock-physics analysis using a combination of heuristic and theoretical models illustrated that mineralogy exerted a significant additional variation on velocity at a given porosity. Failure to account for mineralogy exacerbated inferences about the effect of pore type(s) made using a comparison of P-wave velocity to an inappropriate empirical model (Wyllie) that did not account for pore shape(s). In this analysis, extreme variability in carbonate velocity was observed in only portions of two data sets, when mineralogy was explicitly considered and robust models that accounted for inclusion (pore) shape were used. Results from this analysis resulted in a recommended workflow, including a rock-physics template and dry-rock modulus diagnostics, for the evaluation of lab-based carbonate rock-physics data. The workflow was amenable to further integration with well-based data and other core-based petrophysical measurements (e.g., electrical properties).


2018 ◽  
Vol 6 (4) ◽  
pp. SN101-SN118 ◽  
Author(s):  
Vincent Clochard ◽  
Bryan C. DeVault ◽  
David Bowen ◽  
Nicolas Delépine ◽  
Kanokkarn Wangkawong

The Kevin Dome [Formula: see text] storage project, located in northern Montana, attempted to characterize the Duperow Formation as a potential long-term storage zone for injected [Formula: see text]. A multicomponent (9C) seismic survey was acquired for the Big Sky Carbon Sequestration Partnership over a portion of the Kevin Dome using P- and S-wave sources. Prestack migrated PP, PS, SH, and SV data sets were generated. We then applied several stratigraphic inversion workflows using one or several kinds of seismic wavefield at the same time resulting in joint inversions of each data set. The aim of our study is to demonstrate the benefits of doing quadri-joint inversion of PP-, PS-, SH-, and SV-wavefields for the recovery of the elastic earth parameters, especially the S-wave impedance and density. These are crucial parameters because they can help determine lithology and porefill in the reservoir characterization workflow. Because the inversion workflow always uses the original seismic data recorded in its own time domain, it is necessary to compute registration laws between PP-PS-, PP-SH-, and PP-SV-wavefields using a time shift computation procedure (warping) based on inverted S-wave impedances from inversion of a single wavefield. This generated a significant improvement over methods that rely on attempting to match trace waveforms that may have a different phase, frequency content, and polarity. Finally, we wanted to investigate the reliability of the quadri-joint inversion results in the Bakken/Banff Formations, which have less lateral geologic variation than the underlying Duperow target. This interval shares many of the geophysical characterization challenges common to shale reservoirs in other North American basins. We computed geomechanical parameters, such as Poisson’s ratio and Young’s modulus, which are a proxy for brittleness. Comparison of these results with independent laboratory measurements in the Bakken interval demonstrates the superiority of the quadri-joint inversion method to the traditional inversion using P-wave data only.


Geophysics ◽  
2016 ◽  
Vol 81 (6) ◽  
pp. D599-D609 ◽  
Author(s):  
Piyapa Dejtrakulwong ◽  
Gary Mavko

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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