Petro‐seismic inversion for sandstone properties

Geophysics ◽  
2003 ◽  
Vol 68 (5) ◽  
pp. 1611-1625 ◽  
Author(s):  
Adam P. Koesoemadinata ◽  
George A. McMechan
Keyword(s):  
Shear Wave ◽  
Water Saturation ◽  
Correlation Coefficients ◽  
Clay Content ◽  
Seismic Inversion ◽  
Grid Search ◽  
Quality Factors ◽  
Unknown Parameters ◽  
Seismic Parameters ◽  
Input Variables

We use empirical relations derived from laboratory and log data for sandstones to estimate unknown parameters from given parameters. The known and unknown parameters may be any of the following: compressional and shear wave velocities (Vp and Vs), density (ρ), compressional and shear wave quality factors (Qp and Qs), effective pressure (P), frequency (f), water saturation (S), porosity (φ), clay content (C), fluid permeability (k), and Vp/Vs and Qs/Qp ratios. The goal is to obtain estimates of all thirteen of these petro‐seismic variables from subsets of these as input; whether this is achievable depends on the particular combination of input variables. The inversion typically proceeds through a hierarchy of three levels of parameter estimation, in order of the expected reliability of the estimates. First, we solve for the parameters that can be obtained directly from the fitted empirical equations. Then, a grid search is performed to simultanously fit more than one unknown parameter by finding values that best predict the known parameters. Finally, various approximations are invoked to predict values when the inputs are insufficient to use the direct equations or a grid search. These three procedures can be initiated in any desired order and any number of times. Even if the complete set of seismic parameters (Vp, and Vs, ρ, Qp, Qs, and f) are given, it is not possible to uniquely obtain any of the remaining petrophysical variables (S, φ, C, P, or k) directly from the fitted equations without constraints on (or assumptions about) some of the other variables. There is a trade‐off between porosity and clay content that can be resolved by simultaneous fitting of multiple seismic parameters (i.e., Vp, Vs, and Vp/Vs). The predictability of the parameters from various combinations of the available data is expressed using correlation coefficients (R2) and standard deviations. With optimal input combinations, parameters with R2 ≥ 0.8 are (in order from best to worst) Vp, 100/Qp, ρ, Vs, and S. Other parameters with 0.63 ≥ R2 ≤, 0.79 are (in order from best to worst) φ, Qs/Qp, Vp/Vs, ln k, 100/Qs, and C. P and f are the least reliably estimated. All of the seismic parameters can be accurately estimated if all of the petrophysical parameters are known.

Empirical estimation of viscoelastic seismic parameters from petrophysical properties of sandstone

Geophysics ◽  
2001 ◽  
Vol 66 (5) ◽  
pp. 1457-1470 ◽  
Author(s):  
Adam P. Koesoemadinata ◽  
George A. McMechan
Keyword(s):  
Shear Wave ◽  
Water Saturation ◽  
Clay Content ◽  
Published Data ◽  
Effective Pressure ◽  
Petrophysical Properties ◽  
Quality Factors ◽  
Empirical Estimation ◽  
Reservoir Properties ◽  
Seismic Parameters

Viscoelastic seismic parameters are expressions of underlying petrophysical properties. Theoretical and empirically derived petrophysical/seismic relations exist, but each is limited in the number and the range of values of the variables used. To provide a more comprehensive empirical model, we combined lab measurements from 18 published data sets and well log data for sandstone samples, and determined least‐squares coefficients across them all. The dependent variables are the seismic parameters of bulk density (ρ), compressional and shear wave velocities ([Formula: see text] and [Formula: see text]), and compressional and shear wave quality factors ([Formula: see text] and [Formula: see text]). The independent variables are effective pressure, porosity, clay content, water saturation, permeability, and frequency. As the derived expressions are empirical correlations, no causal relations should be inferred. Prediction of ρ is based on volumetric mixing of the constituents. For [Formula: see text] and [Formula: see text] predictions, separate sets of coefficients are fitted for three water saturation conditions: dry, partially saturated, and fully saturated. Predictions of [Formula: see text] and [Formula: see text] are fitted as functions of porosity, clay content, effective pressure, saturation, and frequency. Predictions of [Formula: see text] are fitted as a function of porosity, clay content, permeability, saturation, frequency, and pressure. Interactions between effective pressure, saturation, and frequency are included. Predictions of [Formula: see text] are obtained from [Formula: see text] and [Formula: see text]. The result is a composite model that is more comprehensive than previous models and that predicts seismic properties from the petrophysical properties. Empirically estimated values of ρ, [Formula: see text], [Formula: see text], [Formula: see text], and [Formula: see text] for the composite data over all saturations predict the measurements with correlation coefficients [Formula: see text] that range from a low of 0.65 (for [Formula: see text],) to a high of 0.90 (for [Formula: see text]). As the fitted relations have been derived from data with limited parameter ranges, extrapolation is not advised, and they are not intended to substitute for locally derived relations based on site‐specific data. Nevertheless, the derived expressions produce representative values that will be useful when approximate, internally consistent predictions are sufficient. Potential future applications include building of seismic reservoir models from petrophysical data and analysis of the sensitivity of seismic data to changes in reservoir properties.

Integrated reservoir characterization of a Utica Shale field

2018 ◽  
Vol 37 (9) ◽  
pp. 656-661
Author(s):  
Jinming Zhu
Keyword(s):  
Seismic Data ◽  
Reservoir Characterization ◽  
Water Saturation ◽  
Clay Content ◽  
Seismic Inversion ◽  
Data Set ◽  
Utica Shale ◽  
Multidisciplinary Study ◽  
3D Seismic Data

We performed an integrated multidisciplinary study for reservoir characterization of a Utica Shale field in eastern Ohio covered by a multiclient 3D seismic data set acquired in 2015. Elastic seismic inversion was performed in-house for effective reservoir characterization of the Utica Shale, which covers the interval from the top of Upper Utica (UUTIC) to the top of Trenton Limestone. Accurate, high-fidelity inversion results were obtained, including acoustic impedance, shear impedance, density, and VP/VS. These consistent inversion results allow for the reliable calculation of geomechanical and petrophysical properties of the reservoir. The inverted density clearly divides the Point Pleasant (PPLS) interval as low density from the overlying UUTIC Shale interval. Both Poisson's ratio (PR) and brittleness unmistakably separate the underlying PPLS from the overlying Utica interval. The PPLS Formation is easier to hydraulically fracture due to its much lower PR. Sequence S4 is the best due to its higher Young's modulus to sustain the open fractures. The calculated petrophysical volumes indisputably delineate the traditional Utica Shale into two distinctive sections. The upper section, the UUTIC, can be described as having 1%–2% total organic carbon (TOC), 3.5%–4.8% porosity, 10%–24% water saturation, and 40%–58% clay content. The lower section, PPLS, can be described as having 3%–4.5% TOC, 5%–9% porosity, 2%–10% water saturation, and about 15%–35% clay content. Both sections exhibit spatial variation of the properties. Nevertheless, the underlying PPLS is obviously a significantly better reservoir and operationally easier to produce.

Integrated reservoir characterization of a Utica Shale with focus on sweet spot discrimination

2020 ◽  
Vol 8 (3) ◽  
pp. SM1-SM14
Author(s):  
Jinming Zhu
Keyword(s):  
Reservoir Characterization ◽  
Water Saturation ◽  
Clay Content ◽  
Seismic Inversion ◽  
Reservoir Properties ◽  
Geomechanical Properties ◽  
Utica Shale ◽  
Characterization Study ◽  
Separate Point

Multiclient 3D seismic data were acquired in 2015 in eastern Ohio for reservoir characterization of the Utica Shale consisting of the Utica and Point Pleasant Formations. I attained accurate, high-fidelity acoustic impedance, shear impedance, density, and [Formula: see text], from elastic inversion. These accurate inversion results allow consistent calculation of reservoir and geomechanical properties of the Utica Shale. I found density critically important affecting the accuracy of other reservoir and geomechanical properties. More than a dozen properties in geologic, geomechanical, and reservoir categories were acquired from logs, cores, and seismic inversion, for this integrated reservoir characterization study. These properties include buried depth, formation thickness, mineralogy, density, Young’s modulus, Poisson’s ratio (PR), brittleness, total organic carbon (TOC), porosity, water saturation, permeability, clay content, and natural fractures. A ternary diagram of core samples from 18 wells demonstrates that the Point Pleasant is dominant with calcite, whereas the Utica mainly contains clay. Inverted density clearly divides Point Pleasant as low density from the overlying Utica. Calculated reservoir properties undoubtedly delineate the traditional Utica Shale as two distinctive formations. I calculated that the Utica Formation contains 1%–2% TOC, 3.5%–4.8% porosity, 10%–24% water saturation, and 40%–58% clay content, whereas Point Pleasant contains 3%–4.5% TOC, 5%–9% porosity, 2%–10% water saturation, and 15%–35% clay content. The PR and brittleness clearly separate Point Pleasant from the overlying Utica, with a lower PR and a higher brittleness index in Point Pleasant than in Utica. The higher brittleness in Point Pleasant makes it easier to frac, leading to enhanced permeability. Both formations exhibit spatial variations of reservoir and geomechanical properties. Nevertheless, the underlying Point Pleasant is obviously better than the Utica Shale with favorable reservoir and geomechanical properties for optimal development and production, although Utica is thicker and shallower. The central and southeastern portions of Point Pleasant have the sweetest reservoirs.

scholarly journals Software Sensor to Enhance Online Parametric Identification for Nonlinear Closed-Loop Systems for Robotic Applications

Sensors ◽  
2021 ◽  
Vol 21 (11) ◽  
pp. 3653
Author(s):  
Lilia Sidhom ◽  
Ines Chihi ◽  
Ernest Nlandu Kamavuako
Keyword(s):  
Degrees Of Freedom ◽  
Closed Loop ◽  
Sliding Mode ◽  
Robot Manipulator ◽  
Parametric Identification ◽  
Recursive Least Squares ◽  
Unknown Parameters ◽  
Closed Loop Identification ◽  
Input Variables ◽  
Robotic Applications

This paper proposes an online direct closed-loop identification method based on a new dynamic sliding mode technique for robotic applications. The estimated parameters are obtained by minimizing the prediction error with respect to the vector of unknown parameters. The estimation step requires knowledge of the actual input and output of the system, as well as the successive estimate of the output derivatives. Therefore, a special robust differentiator based on higher-order sliding modes with a dynamic gain is defined. A proof of convergence is given for the robust differentiator. The dynamic parameters are estimated using the recursive least squares algorithm by the solution of a system model that is obtained from sampled positions along the closed-loop trajectory. An experimental validation is given for a 2 Degrees Of Freedom (2-DOF) robot manipulator, where direct and cross-validations are carried out. A comparative analysis is detailed to evaluate the algorithm’s effectiveness and reliability. Its performance is demonstrated by a better-quality torque prediction compared to other differentiators recently proposed in the literature. The experimental results highlight that the differentiator design strongly influences the online parametric identification and, thus, the prediction of system input variables.

Effects of oil‐water saturation on shear‐wave splitting in multicomponent seismic data

2007 ◽  
Author(s):  
Zhongping Qian ◽  
Xiang‐Yang Li ◽  
Mark Chapman ◽  
Yonggang Zhang ◽  
Yanguang Wang
Keyword(s):  
Shear Wave ◽  
Seismic Data ◽  
Water Saturation ◽  
Shear Wave Splitting ◽  
Multicomponent Seismic ◽  
Wave Splitting ◽  
Oil Water

scholarly journals Gas-bearing sands appraisal for Zamzama Gas field in Pakistan through inverted elastic attributes assisted with PNN approximation of petrophysical properties

2021 ◽  
Author(s):  
Zahid U. Khan ◽  
◽  
Mona Lisa ◽  
Muyyassar Hussain ◽  
Syed A. Ahmed ◽  
...  
Keyword(s):  
Elastic Properties ◽  
Clay Content ◽  
Seismic Inversion ◽  
Indus Basin ◽  
Minimal Risk ◽  
Gas Field ◽  
Lower Indus Basin ◽  
Heterogeneity Effects ◽  
Prestack Seismic Inversion ◽  
Gas Bearing

The Pab Formation of Zamzama block, lying in the Lower Indus Basin of Pakistan, is a prominent gas-producing sand reservoir. The optimized production is limited by water encroachment in producing wells, thus it is required to distinguish the gas-sand facies from the remainder of the wet sands and shales for additional drilling zones. An approach is adopted based on a relation between petrophysical and elastic properties to characterize the prospect locations. Petro-elastic models for the identified facies are generated to discriminate lithologies in their elastic ranges. Several elastic properties, including p-impedance (11,600-12,100 m/s*g/cc), s-impedance (7,000-7,330 m/s*g/cc), and Vp/Vs ratio (1.57-1.62), are calculated from the simultaneous prestack seismic inversion, allowing the identification of gas sands in the field. Furthermore, inverted elastic attributes and well-based lithologies are incorporated into the Bayesian framework to evaluate the probability of gas sands. To better determine reservoir quality, bulk volumes of PHIE and clay are estimated using elastic volumes trained on well logs employing Probabilistic Neural Networking (PNN), which effectively handles heterogeneity effects. The results showed that the channelized gas-sands passing through existing well locations exhibited reduced clay content and maximum effective porosities of 9%, confirming the reservoir's good quality. Such approaches can be widely implemented in producing fields to completely assess litho-facies and achieve maximum production with minimal risk.

AN INTEGRATED PETROPHYSICAL CHARACTERIZATION OF A SILICICLASTIC TIGHT GAS RESERVOIRS IN NEUQUÉN BASIN, WESTERN ARGENTINA

2021 ◽  
Author(s):  
Nicolas Carrizo ◽  
◽  
Emiliano Santiago ◽  
Pablo Saldungaray ◽  
◽  
...  
Keyword(s):  
Water Saturation ◽  
Seismic Inversion ◽  
Tight Gas ◽  
Analysis Model ◽  
Drilling Rig ◽  
Irreducible Water Saturation ◽  
Neuquen Basin ◽  
Open Hole ◽  
Neuquén Basin ◽  
Pulsed Neutron

The Río Neuquén field is located thirteen miles north west of Neuquén city, between Neuquén and Río Negro provinces, Argentina. Historically it has been a conventional oil producer, but some years ago it was converted to a tight gas producer targeting deeper reservoirs. The targeted geological formations are Lajas, which is already a known tight gas producer in the Neuquén basin, and the less known overlaying Punta Rosada formation, which is the main objective of the current work. Punta Rosada presents a diverse lithology, including shaly intervals separating multiple stacked reservoirs that grade from fine-grained sandstones to conglomerates. The reservoir pressure can change from the normal hydrostatic gradient to up to 50% of overpressure, there is little evidence of movable water. The key well in this study has a comprehensive set of open hole logs, including NMR and pulsed-neutron spectroscopy data, and it is supported by a full core study over a 597ft section in Punta Rosada. Additionally, data from several offset wells were used, containing sidewall cores and complete sets of electrical logs. This allowed to develop rock-calibrated mineral models, adjusting the clay volume with X-ray diffraction data, porosity and permeability with confined core measurements, and link the logs interpretation to dominant pore throat radius models from MICP Purcell tests at 60,000 psi. Several water saturation models were tested attempting to adjust the irreducible water saturation with NMR and Purcell tests at reservoir conditions. As a result, three hydraulic units were defined and characterized, identifying a strong correlation with lithofacies observed in cores and image logs. A cluster analysis model allowed the propagation of the facies to the rest of the wells (50). Finally, lithofacies were distributed in a full-field 3D model, guided by an elastic seismic inversion. In the main key well, in addition to the open hole logs and core data, a cased hole pulsed neutron log (PNL) was also acquired , which was used to develop algorithms to generate synthetic pseudo open hole logs such as bulk density and resistivity, integrated with the spectroscopy mineralogical information and other PNL data to perform the petrophysical evaluation. This enables the option to evaluate wells in contingency situations where open hole logs are not possible or are too risky, and also in planned situations to replace the open hole data in infill wells, saving considerable drilling rig time to reduce costs during this field development phase. Additionally, the calibrated cased hole model can be used in old wells already drilled and cased in the Punta Rosada formation. This paper explores the integration of different core and log measurements and explains the development of rock-calibrated petrophysical and rock types models for open and cased hole logs addressing the characterization challenges found in tight gas sand reservoirs. The results of this study will be crucial to optimize the development of a new producing horizon in a mature field.

scholarly journals Boron adsorption in soils from the State of São Paulo, Brazil

2000 ◽  
Vol 35 (2) ◽  
pp. 413-421 ◽  
Author(s):  
LUÍS REYNALDO FERRACCIÚ ALLEONI ◽  
OTÁVIO ANTONIO DE CAMARGO
Keyword(s):  
Aluminum Oxide ◽  
Correlation Coefficients ◽  
Clay Content ◽  
Sao Paulo ◽  
The State ◽  
São Paulo ◽  
Aluminum Oxides ◽  
Freundlich Isotherms ◽  
Physical Attributes ◽  
Boron Adsorption

Boron adsorption was studied in five representative soils (Rhodic Hapludox, Arenic Paleudalf and three Typic Hapludox) from the State of São Paulo, Brazil. Adsorption was higher in the clayey Oxisols, followed by the Alfisol and the coarser Oxisols. Calcium carbonate promoted an increase in the amount of adsorbed boron in all soils, with the most pronounced effect in the coarser-textured Oxisols. High correlation coefficients were found between adsorbed boron and clay and amorphous aluminum oxide contents and specific surface area (r = 0.79, 0.76 and 0.73, respectively, p < 0.01). Clay content, free aluminum oxide, and hot CaCl2 (0.01 mol L-1)-extracted boron explained 93% of the variation of adsorbed boron. Langmuir and Freundlich isotherms fitted well to the adsorbed data, and highest values for maximum boron adsorption were found in clayey soils, which were significantly correlated with contents of total, free and amorphous iron and aluminum oxides, as well with the physical attributes. Ninety four percent of the variation in the maximum adsorption could be related to the free iron content.

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