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Rock physics plays an important role in the oil, gas, and water industries by providing essential data for reservoir management. This study focuses on predicting Shear Wave Velocity (Vs), a key geophysical parameter, using the Deep Belief Network (DBN) and Random Forest (RF) algorithms. The dataset is divided for training, validation, and testing, revealing that the DBN model surpasses the RF and empirical models in accuracy. With a low RMSE value of 0.0398 km/s in testing and an R2 of 0.9775, the DBN model demonstrates precision in Vs prediction. The analysis identifies specific parameters—Measure Depth (MD), Caliper (CALL), Gamma Ray (GR), Shallow Electrical Resistivity (RES-S), Medium Electrical Resistivity (RES-M), Deep Electrical Resistivity (RES-D), Compressional Wave Velocity (DCT), Neutron Porosity (NPHI), and Photoelectric Coefficient Index (PEF)—as significantly influencing Vs, while CALI and GR have a relatively lesser effect. The results of the Vs prediction indicated that the DBN algorithm excels in deep feature extraction, unsupervised pretraining, and efficient handling of complex data. Ultimately, the DBN algorithm proves to be a superior and time-saving alternative for Vs prediction and analysis in subsurface reservoirs. • Rock physics aids oil, gas, and water industries through crucial reservoir data. • Deep Belief Network (DBN) excels in Vs prediction with superior performance. • DBN model achieves remarkable precision with a low RMSE of 0.0398 km/s. • Correlation analysis identifies key parameters influencing shear wave velocity (Vs). • DBN algorithm proves a time-saving, reliable alternative for Vs prediction in subsurface reservoirs. [ABSTRACT FROM AUTHOR]

Determining BPP is one of the critical parameters for developing oil and gas reservoirs, and has this parameter requires a lot of time and money. As a result, this study aims to develop a new predictive model for BPP that uses some available input variables such as solution oil ratio (Rs), gas specific gravity (γg), API Gravity (API). In this study, two innovatively combined hybrid algorithms, DWKNN-GSA and DWKNN-ICA, are developed to predict BPP. The study outcomes show the models developed are capable of predicting BPP with promising performance, where the best result was achieved for DWKNN-ICA (RMSE = 0.90276 psi and R² = 1.000 for the test dataset). Moreover, the performance comparison of the developed hybrid models with some previously developed models revealed that the DWKNN-ICA outperforms the former empirical models concerning perdition accuracy. In addition to presenting new techniques in the present study, the effect of each of the input parameters on BPP was evaluated using Spearman's correlation coefficient, where the API and Rs have the lowest and the highest impact on the BPP. [ABSTRACT FROM AUTHOR]

One of the challenges in reservoir management is determining the fracture density (FVDC) in reservoir rock. Given the high cost of coring operations and image logs, the ability to predict FVDC from various petrophysical input variables using a supervised learning basis calibrated to the standard well is extremely useful. In this study, a novel machine learning approach is developed to predict FVDC from 12-input variable well-log based on feature selection. To predict the FVDC, combination of two networks of multiple extreme learning machines (MELM) and multi-layer perceptron (MLP) hybrid algorithm with a combination of genetic algorithm (GA) and particle swarm optimizer (PSO) has been used. We use a novel MELM-PSO/GA combination that has never been used before, and the best comparison result between MELM-PSO-related models with performance test data is RMSE = 0.0047 1/m; R2 = 0.9931. According to the performance accuracy analysis, the models are MLP-PSO < MLP-GA < MELM-GA < MELM-PSO. This method can be used in other fields, but it must be recalibrated with at least one well. Furthermore, the developed method provides insights for the use of machine learning to reduce errors and avoid data overfitting in order to create the best possible prediction performance for FVDC prediction. [ABSTRACT FROM AUTHOR]

Gas condensate reservoirs display unique phase behavior and are highly sensitive to reservoir pressure changes. This makes it difficult to determine their PVT characteristics, including their condensate viscosity, which is a key variable in determining their flow behavior. In this study, a novel machine learning approach is developed to predict condensate viscosity in the near wellbore regions (μ c) from five input variables: pressure (P), temperature (T), initial gas to condensate ratio (RS), gas specific gravity (γg), and condensate gravity (API). Due to the absence of accurate recombination methods for determining μc machine learning methods offer a useful alternative approach. Nine machine learning and hybrid machine learning algorithms are evaluated including novel multiple extreme learning machine (MELM), least squares support vector machine (LSSVM) and multi-layer perceptron (MLP) and each hybridized with a particle swarm optimizer (PSO) and genetic algorithm (GA). The new MELM algorithm has some advantages including 1) rapid execution, 2) high accuracy, 3) simple training, 4) avoidance of overfitting, 5) non-linear conversion during training, 6) no trapping at local optima, 6) fewer optimization steps than SVM and LSSVM. Combining MELM with PSO, to find the best control parameters, further improves its performance. Analysis indicates that the MELM-PSO model provides the highest μ c prediction accuracy achieving a root mean squared error (RMSE) of 0.0035 cP and a coefficient of determination (R2) of 0.9931 for a dataset of 2269 data records compiled from gas-condensate fields around the world. The MELM-PSO algorithm generates no outlying data predictions. Spearman correlation coefficient analysis identifies that P, γg and Rs are the most influential variables in terms of condensate viscosity based on the large dataset studied. • 2269 viscosity data records compiled from worldwide gas condensate fields. • Machine learning with optimizers reliably predicts condensate viscosity (μc). • Empirical models do not accurately predict μc and are not fit for purpose. • MELM-PSO model yields best μc predictions outperforming other models. • Pressure, gas gravity and condensate/gas ratio have greatest influence. [ABSTRACT FROM AUTHOR]

A key parameter when drilling for gas and oil is to determine the safe mud weight window (SMWW) to ensure wellbore stability as part of a quantitative risk assessment (QRA). This study determines SMWW by predicting acceptable upper and lower limits of the bottom hole pressure window during over-balance drilling method. A novel machine learning method is developed to predict SMWW from ten well-log input variables subject to feature selection. 3389 data records from three South Pars gas field (Iran) wells include data from: uncorrected spectral gamma ray; potassium; thorium; uranium; photoelectric absorption factor; neutron porosity; bulk formation density; corrected gamma ray adjusted for uranium content; shear-wave velocity and compressional-wave velocity. Combinations of these well logs are tuned to provide predictions of the SMWW, measured in terms of subsurface pore and fracture pressures, using machine learning (ML) algorithms hybridized with optimizers. The ML algorithms assessed are multiple layer extreme learning machine (MELM) and least squares support vector machine (LSSVM), hybridized with genetic (GA) and particle swarm (PSO) optimizers. This new algorithm (MELM) incorporates special features that improve its prediction performance, speeds up its training, inhibits overfitting and involves less optimization in the model's construction. By combining MELM with PSO, its optimum control parameters are rapidly determined. The results reveal that the MELM-PSO combination provides the highest SMWW prediction accuracy of four models evaluated. For the testing subset MELM-PSO achieves high prediction performance of pore pressure (RMSE = 12.76 psi; R2 = 0.9948) and fracture pressure (RMSE = 15.71 psi; R2 = 0.9967). Furthermore, the model demonstrates that once trained with data from a few wells, it can be successfully applied to predict unseen data in other South Pars gas field wells. The findings of this study can provide a better understanding of how ML methods can be applied to accurately predict SMWW. • Four hybrid algorithms used for determining safe mud weight window based on pore and fracture pressures. • MELM-PSO outperforms MELM-GA, LSSVM-PSO and LSSVM -GA models. • Ten petrophysical variables were used as input to determination of safe mud weight window. [ABSTRACT FROM AUTHOR]