Saurabh Datta Gupta
@iitism.ac.in
Assistant Professor; Department of Applied Geophysics
Indian Institute of Technology (Indian School of Mines), Dhanbad
10 years of Oil and Gas industry experience as a reservoir geophysicist. At present working as faculty with exploration seismic and reservoir geophysics specialization.
RESEARCH INTERESTS
Computational Geophysics, Quantitative And Qualitative Seismic Interpretation, Reservoir Characterization, Rock Physics Analysis, Seismic Inversion, Geo-Cellular Modeling, 4D And Passive Seismic Analysis, Study On CBM And Carbonate Reservoir, Study On Unconventional Energy Sources, Carbon Capture And Storage (CCS) For Oil And Gas Reservoir
Scopus Publications
Scholar Citations
Scholar h-index
Scholar i10-index
Scopus Publications
Pydiraju Yalamanchi and Saurabh Datta Gupta
Springer Science and Business Media LLC
AbstractAnalyzing the pore structure in carbonate reservoirs plays a crucial role in predicting fluid flow characteristics within these formations. The goal of the study was to use machine learning techniques for pore structure analysis and estimation of permeability in carbonate reservoirs. We implemented these algorithms by examining 2D scanning electron microscope (SEM) images of carbonate samples from the Jaisalmer sub-basin captured at various magnifications. In the initial stage of the analysis, various binarization algorithms were applied to determine carbonate sample porosity. Among these algorithms, the MaxEntropy algorithm gave a porosity value closely aligned with those obtained through petrography analysis. We employed the watershed algorithm to find the pore network parameters of carbonate samples at various magnifications. We observed that changes in magnification affected pore network parameters, resulting in a reduction in pore size distribution, throat radius, and grain size. Subsequently, we employed the numerical lattice Boltzmann method (LBM) to estimate the permeability of carbonate samples and compared to values derived from well logs. We employed machine learning (ML) algorithms, specifically Artificial Neural Network (ANN) and Support Vector Machine (SVM), to predict the permeability of carbonate samples. The input features for these models were the pore network parameters, while the LBM permeability values served as the output. We examine the prediction performance of these methods against the measured LBM permeability by conducting the error analysis and the coefficient of determination ($${R}^{2}$$ R 2 ) calculation. Our findings revealed that the ANN models outperformed the SVM models. Specifically, the ANN model displayed an impressive R2 value of 0.892, along with root mean square error (RMSE), mean squared error (MSE) and, mean absolute error (MAE) values of 1.927, 3.716 and 1.580, respectively. In contrast, the SVM model yielded an R2 value of 0.849, with RMSE, MSE and, MAE values of 2.324, 5.401 and, 2.166 respectively, when assessed on testing data of measured permeability. This study found that ANN is more dependable, robust, and precise than SVM in forecasting carbonate sample permeability.
Shantanu Chakraborty, Saurabh Datta Gupta, Varsha Devi, and Pydiraju Yalamanchi
Springer Science and Business Media LLC
Raj Kiran, Rajeev Upadhyay, Vinay Kumar Rajak, Saurabh Datta Gupta, and Harharjot Pama
Elsevier BV
Rajeev Upadhyay, Saurabh Datta Gupta, and Vinay Kumar Rajak
Springer Science and Business Media LLC
Santosh Dhubia, Alok Kumar Routa, Saurabh Datta Gupta, and Priya Ranjan Mohanty
Springer Science and Business Media LLC
AbstractThe development of an accurate velocity model is the significant target in the Full Waveform Inversion (FWI) process where the data fitting process is carried out based on an ill-posed technique. In the FWI technique optimization process plays a crucial role through which objective function minimizes, which is related to the misfit function between observed and modelled data. However, the influence of external factors such as data fitting errors (local minima) and the presence of noise in data are involved in the success of this processing technique. The artefacts that arise during gradient computation also affect this processing technique. This study presents a strategy to mitigate the influence of these local minima and other artefacts based on the velocity variation coefficient where an angle-dependent gradient conditioning approach has been proposed. It is an auto-controlled process in which the primary mechanism updates the velocity model from a large angle scale to a smaller angle scale when iteration begins. At each iteration, it preserves the previous result whereby it does not scatter or overlap with the previous one. It covers all the angles smoothly which helps in minimizing the data misfit and providing a high-resolution velocity model. The proposed conditioning approach is demonstrated by implementing the Marmousi model, and the result proves that the method provides a much-improved velocity inversion result which is attained with reasonable iterations. This study represents of a suitable procedure for the FWI processing technique where less sensitive artefacts are identified with negligible time consumption. Furthermore, it also helps to reduce the cycle skips and improve convergence in any complex scenario.
Nabanita Pradhan and Saurabh Datta Gupta
Springer Science and Business Media LLC
AbstractAmplitude variation with offset (AVO) analysis is an important tool for identifying natural gas-bearing reservoirs. The changes in seismic amplitudes based on the variation of density and velocity of the rock matrix are captured through the AVO analysis. The current work was performed in the Ghotaru region of the Jaisalmer Sub-basin area, where limited and discrete hydrocarbon discoveries were observed from the Lower Goru Formation during the earlier various exploration campaigns. The discrete nature of the reservoir lithofacies developed challenging scenarios for the successful exploratory campaign. The campaign encountered more difficulties because of limited advanced datasets, which affected the study to capture the extension of hydrocarbon-bearing reservoir lithofacies and its characterization towards a successful exploration campaign. This study shows the way to overcome these challenges using an existing conventional dataset. The study shows the possibility of AVO analysis using a post-stack seismic dataset. A unique conversion method from post-stack to pre-stack seismic is introduced in this study based on the uses of the integrated velocity model. An integrated, robust velocity model was developed with consideration of anisotropy factors. Introducing a machine learning-based algorithm in the petrophysical study, including the conventional approach, provides a robust validation of this work. Intercept (A) and gradient (B) are the basic outcome of AVO analysis. The well-based study and AVO analysis based on intercept (A) and gradient (B) complement each other for finding hydrocarbon-bearing reservoir rock. Cross-plots and AVO analysis show the reservoir's lithofacies extension and fluids. The study reveals the potential of natural gas retained in the Lower Goru Formation, which is composed of patchy sandstone. Two AVO classes (Class I and Class III) of gas-bearing sandstone have been identified in this study. This study presents a unique method for identifying natural gas reservoirs with limited old conventional data.
Santosh Dhubia, Alok K Routa, Saurabh Datta Gupta, Priya R Mohanty, and P H Rao
Springer Science and Business Media LLC
Saurabh Datta Gupta, Sugata Kumar Sinha, and Raman Chahal
Springer Science and Business Media LLC
AbstractThe Rajasthan basin situates in the western part of India. The basin architecture comprises three significant sub-basins such as Barmer-Sanchor, Bikaner-Nagaur and Jaisalmer. Barmer-Sanchor and Bikaner-Nagaur sub-basins are intracratonic categories, whereas the Jaisalmer sub-basin comes under intracratonic nature. The current study was conducted in the Jaisalmer sub-basin. The study was conducted in two regions in the Jaisalmer sub-basin through a comparative quantitative interpretation study with the help of two vintages seismic surveys. Ghotaru and Bandha are two adjacent areas in the Jaisalmer sub-basin where Ghotaru has seen few hydrocarbon discoveries; however, no such discoveries are encountered in the Bandha area. The current study was concentrated on the Jaisalmer limestone formation in the Jurassic age. The sub-basin and its related study area have been structurally deformed due to various tectonic activities. Structural deformation was played a crucial role in changing the rock property of limestone facies. A post-stack seismic inversion was carried out to capture the rock property changes in the limestone reservoir based on P-impedance values. Development of high P-impedance was observed in the Ghotaru region compared to the Bandha region from this study. A frequency changes of the limestone lithofacies with structural components was also captured in this study. The high impedance limestone lithofacies is a probable hydrocarbon-bearing reservoir unit in the Jaisalmer Formation of the Ghotaru region.
Priyanka Gautam and Saurabh Datta Gupta
Elsevier BV
S. P. Vijay Kumar, S. Ganesh Kumar, and Saurabh Datta Gupta
Springer Science and Business Media LLC
Occurrence of earthquake generates both horizontal and vertical ground motions. In saturated sands, combination of generated ground motions and pore water pressures induces soil liquefaction. In this study, a composite skirted ground reinforcement system was developed to mitigate generation of pore water pressure in liquefiable soils and also to attenuate incoming ground motions to the foundation. The composite system contains Polyurethane foam as an isolation barrier for ground motion attenuation with stone columns for improving both soil densification and drainage. The performance of this composite reinforcement system was evaluated under repeated acceleration loading conditions to estimate its efficiency. For testing, saturated ground model having 40% and 60% relative density was prepared and investigated with and without the composite reinforcement system. Test results showed that, the developed skirted ground reinforcement system effectively mitigates the interaction of incoming ground motions with the foundation and also improves the reliquefaction resistance of soil compared to that of unreinforced ground.
Pydiraju Yalamanchi and Saurabh Datta Gupta
Springer Science and Business Media LLC
The frequent variability of petrophysical properties makes hydrocarbon exploration challenging in carbonate reservoirs. Nowadays, quantitative interpretation (QI) is an essential part of hydrocarbon exploration in a complex reservoir, which needs adequate rock physics data at the well level. However, sometimes the relevant data are not available in earlier discovered oil and gas fields. We observed that the old oil and gas fields in the onshore parts of India have a scarcity of density and compressional velocity (Vp) data at the well level. Gardner's empirical expression provides the scope to estimate Vp from acquired density data and vice versa. However, there are two constants in this relationship, and these are different for different saturation cases of the reservoir due to different mineralogical content in the reservoir rock. The current study aims to identify suitable rock mineral mixing methods and their related uncertainty for estimating Gardner's constants. This uncertainty leads to the estimation of the degree of unwanted flexibility for Vp measurement. Improper selection of the rock mineral mixing method generates uncertainties during the fluid substitution model, mainly where available data are limited. A machine learning (ML) approach based on the naïve Bayes algorithm was adopted in this study to select the appropriate rock mineral mixing method from a limited data set. The study was performed in a carbonate reservoir in an onshore sedimentary basin of western India. The ML study shows that the Reuss rock mineral mixing method is suitable for the computation of Gardner's constant in different saturation models for this carbonate reservoir, with less uncertainty.
Raman Chahal and Saurabh Datta Gupta
Elsevier BV
AbstractGeoscientific evidence shows that various parameters such as compaction, buoyancy effect, hydrocarbon maturation, gas effect and tectonic activities control the pore pressure of sub-surface geology. Spatially controlled geoscientific data in the tectonically active areas is significantly useful for robust estimation of pre-drill pore pressure. The reservoir which is tectonically complex and pore pressure is changing frequently that circumference motivated us to conduct this study. The changes in pore pressure have been captured from the fine-scale to the broad scale in the Jaisalmer sub-basin. Pore pressure variation has been distinctly observed in pre- and post-Jurassic age based on the current study. Post-stack seismic inversion study was conducted to capturing the variation of pore pressure. Analysis of low-frequency spectrum and integrated interval velocity model provided a detailed feature of pore pressure in each compartment of the study area. Pore pressure estimated from well log data was correlated with seismic inversion based result. Based on the current study one well has been proposed where pore pressure was estimated and two distinguished trends are identified in the study zone. The approaches of the current study were analysed thoroughly and it will be highly useful in complex reservoir condition where pore pressure varies frequently.
Sugata Kumar Sinha and Saurabh Datta Gupta
Springer Science and Business Media LLC
The coal formation of the Damodar basin is found in parts of the Indian states of West Bengal and Jharkhand. However, the potentiality of the coal formation and its presence across the basin are not equal. Both East Bokaro and West Bokaro are highly fertile and productive for high-quality coal. However, due to the lack of coal seams, no significant discoveries can be made between these two regions. The purpose of the present study is to identify the reasons for the lack of coal seam between the areas of the eastern and western Bokaro of the Damodar basin. The study area was chosen near the Lugu hill, adjacent to the Ghato area in the West Bokaro based on the geological significance. The presence of the coal seam is not identified in the study area. To reach the objective of the study an integrated geological model was developed based on laboratory analysis, computational and analytical approach. Newly acquired shallow seismic data, earlier acquired digitized gravity data and drilled well data were used for the study. Rock samples were collected from discrete areas of the Lugu hill for laboratory analysis. The integrated geological depositional model suggests that crustal thinning and basement upliftment is the significant reason for the absence of coal seam in between East and West Bokaro. Several tectonic activities and associated intrusion are another factor for the absence of coal in the area.
Nabanita Pradhan, Saurabh Datta Gupta, and P R Mohanty
Springer Science and Business Media LLC
Measurement of velocity anisotropy is an essential parameter for capturing the heterogeneity of sub-surface geology to characterise the hydrocarbon-bearing reservoir. The incorporation of velocity anisotropy parameters during the preparation of the 3D velocity model represents a robust result in a challenging geological set-up during interpretation. Generally, we can observe that the shale formation is more sensitive to velocity anisotropy response in comparison with other formations such as sandstone, siltstone for clastic reservoir or limestone and dolomite for carbonate reservoir. This study was performed mostly in the high amount shale section mixed with limestone and claystone of the Jaisalmer sub-basin area which lies in the western part of India. The preparation of the velocity model for frequent changes of lithology in the clastic and carbonate reservoir is challenging due to several changes of velocity which show a limitation in the result of the gridded velocity model. The objective of this study is to capture the changes of compressional and shear wave velocity in mixed lithology of the significant shale formation. The idea was due to the inclusion of the anisotropy incorporated changed velocity during the preparation of the gridded velocity model for correctly identified lithology. The shale formation which is the zone of investigation of the current study is situated over a carbonate sequence, and an estimated velocity anisotropy factor of this shale formation will contribute significantly during the cumulative study of velocity modelling of all formation. The current study shows that shale formation shows the character of orthorhombic anisotropy; however, this study was performed based on significant changes of well log data and related effects of vertically transverse isotropic parameters of the shale formation. The fundamental Thomsen anisotropy parameters were estimated by capturing the deviation of five independent stiffness coefficients. Significant changes in evaluated shale velocity were observed after the incorporation of the estimated Thomsen parameter in velocity values.
Saurabh Datta Gupta and Ramesh Gupta
Springer Science and Business Media LLC
Cambay basin is an intra-cratonic rift graben formed as a result of rifting which was occurred in late Cretaceous with Deccan lava eruption through linear trending NNW to SSE directional basin. The Deccan basalt forms the basement over which more than 7–11 km thick piles of Tertiary sediments have been deposited during syn-rift and post-rift phases of basin development. Cambay basin has been considered as one of the significant hydrocarbon prolific basin in India. The biggest challenge in current days for this basin is further exploration or exploration under development stage in small marginal field or unexplored left out areas in the basin part as most of the areas are already explored/discovered by various small to big E&P (exploration & production) industrial players. In this present study one such small marginal field has been chosen for “Exploration under Development” portfolio in mid Cambay basin. The amount of oil-in-place volume, investment and techno-economics analysis of small marginal field has made this study area. In view of further hydrocarbon exploration in this area this kind of study will provide a robust support in limited dataset. The reservoir sand quality of the study area is discrete, thin and less permeable. This kind of sand body detection through classical seismic interpretation approach is difficult and there will be always a big amount of uncertainties for findings the pay reservoir sand. In view of the limitation of available data and challenging geological setup of the reservoir, a quantitative approach has been taken to detect the thin reservoir sand in this study area. Primarily coloured inversion technique has been applied on post-stack seismic data based upon well to seismic correlation and reservoir sand detection in seismic interpretation and well log property analysis. This technique has produced higher detectability impedance/property volume with respect to normal post-stack seismic data signature. Based on high contrast impedance/elastic property further seismic based attribute analysis on reservoir section has been performed. The attribute analysis has been made along surface and 3D seismic data level, provided clear image about the thin hydrocarbon sand reservoir. Based upon quantitative interpretation approach coloured inverted volume the prospect was chosen for further drilling in the study area and drilling of that sand was turned to be a hydrocarbon discovery prospect. The unconventional approaches e.g. coloured inversion with limited dataset for this kind of small marginal field has potential to find the hydrocarbon.
Rima Chatterjee, Saurabh Datta Gupta, and Partha Pratim Mandal
Springer Science and Business Media LLC
The Deccan trap basalt, laid down by multiple lava flows during upper Cretaceous to Paleocene times forms the basement of current study in Cambay basin. As such, there is great interest and value in fracture detection and evaluation of fractured basement reservoirs in the Cambay basin. The procedure for identification and evaluation of natural as well as induced fractures in basaltic basement of the Cambay basin is presented in this work. In this study formation micro-imager (FMI) and extended range micro-imager (XRMI) log data for fracture identification is used. The Deccan trap basaltic basement of the study area, comprising five wells in the Tarapur-Cambay block, has potential for holding commercial hydrocarbon due to the presence of fractures and weathered basement. Both image logs (FMI, XRMI) identify three types of fracture including open (conductive), partially open and closed (resistive) fractures, of which open and partially open fractures are important for hydrocarbon accumulation. Fracture dip ranges from 10° to 80°. Image logs have also identified washout, breakout and drilling-induced fracture zones. The strike direction of the open natural fractures for four wells varies from N60°E to N30°E whereas the strike direction of most natural fracture in the fifth well is oriented towards N20°W. The orientations of drilling-induced fractures and breakouts may be interpreted for the in-situ stress direction over the logged interval. Drilling-induced tensile fractures, identified over the depth interval of 1969–1972 m, and borehole breakouts over the interval of 1953–1955 m in one well, suggest an orientation of maximum in-situ horizontal compressive stress (SH) lies in the north-south direction. The azimuths of open natural fractures in the same well vary from north-south to N30°E. It is expected that the direction of fluid flow will be controlled by open natural fractures and therefore would be in a direction parallel to the SH direction, which is orthogonal to the minimum horizontal stress (Sh) direction. The orientations observed are consistent with the present day SH direction in the study area of Cambay basin.
Rima Chatterjee, Saurabh Datta Gupta, and M.Y. Farroqui
Elsevier BV
Abstract Full stack seismic data in Cambay basin, India, shows limited contrast between sandstone reservoirs and other lithologies. The seismic inversion result has been used here to convert the seismic reflection data into impedance log at each point and the ratio of every point. Wavelet estimations have been carried out for four wells namely, AM-11, AM-12, AM-13 and AM-14 lying between Sanand and Nawagam oilfields located in the Ahmedabad–Mehsana block of Cambay basin. The combination of P-impedance and compressional wave velocity (Vp) to shear wave velocity (Vs) ratio has been used to delineate the pay sand. Reservoir pay sand in Eocene pay formation has been delineated from these wells. The cross plotting technique between Vp/Vs (from four wells AM-11 to AM-14 under the study area) and P-impedance values has differentiated sand and shale. It is observed that the high P-impedance sand is associated with low porosity (15–18%) values while the low P-impedance sand is associated with relatively high porosity (20–25%) values.
Rima Chatterjee, Saurabh Datta Gupta, and M Y Farooqui
Oxford University Press (OUP)
Rima Chatterjee, Saurabh Datta Gupta, and M Y Farooqui
Oxford University Press (OUP)
Low-resistivity pay sands have been identified in four wells, namely: AM-7, AM-8, TA-1 and TA-5, which penetrate the Eocene pay-IV (EP-IV) sand unit of the Kalol formation in the Cambay basin. These wells are located near the Dholka and Kanwara oilfields in the Cambay basin. The main objective of this paper is to evaluate nuclear magnetic resonance (NMR) logs of the low-resistivity reservoirs from these four wells and to determine the petrophysical properties more accurately than conventional logs have done. The thickness of low-resistivity sand varies from 5 to 17?m in the wells under the study area. The formation has been characterized by a high surface area; thus irreducible water saturation (Swi) is high. The resistivity of these pay zones varies from 1 to 8 ?m and the total NMR porosity ranges from 15% to 50%. The free fluid porosity ranges from 2% to 5% in wells TA-1 and TA-5 and 12?20% in wells AM-7 and AM-8. The Timur?Coates/SDR model derived that the permeability of the low-resistivity reservoir ranges from 0.8 to 1.5 md in wells TA-1 and TA-5 and 10?110 md in wells AM-7 and AM-8.
Saurabh Datta Gupta, Rima Chatterjee, and M. Y. Farooqui
Springer Science and Business Media LLC
The Cambay Basin is 450-km-long north–south-trending graben with an average width of 50 km, having maximum depth of about 7 km. The origin of the Cambay and other Basins on the western margin of India are related to the break up of the Gondwana super-continent in the Late-Triassic to Early-Jurassic (215 ma). The structural disposition of the Pre-Cambrian basement—a complex of igneous and metamorphic rocks exposed in the vicinity of the Cambay Basin—controls its architecture. The principal lineaments in the Basin are aligned towards NE-SE, ENE-WSW and NNW-SSE, respectively. Rock physics templates (RPTs) are charts and graphs generated by using rock physics models, constrained by local geology, that serve as tools for lithology and fluid differentiation. RPT can act as a powerful tool in validating hydrocarbon anomalies in undrilled areas and assist in seismic interpretation and prospect evaluation. However, the success of RPT analysis depends on the availability of the local geological information and the use of the proper model. RPT analysis has been performed on well logs and seismic data of a particular study area in mid Cambay Basin. Rock physics diagnostic approach is adopted in the study area placed at mid Cambay Basin to estimate the volume in the reservoir sands from 6 wells (namely; A, B, C, D, E and F) where oil was already encountered in one well, D. In the study area, hydrocarbon prospective zone has been marked through compressional (P wave) and shear wave (S wave) impedance only. In the RPT analysis, we have plotted different kinds of graphical responses of Lame’s parameters, which are the function of P-wave velocity, S-wave velocity and density. The discrete thin sand reservoirs have been delineated through the RPT analysis. The reservoir pay sand thickness map of the study area has also been derived from RPT analysis and fluid characterization. Through this fluid characterization, oil-bearing thin sand layers have been found in well E including well D. The sand distribution results prove that this methodology has able to perform reservoir characterization and seismic data interpretation more quantitatively and efficiently.
Saurabh Datta Gupta, Rima Chatterjee, and M Y Farooqui
Oxford University Press (OUP)
Unconventional reservoirs such as fractured basalts, shale gas and tight sand are currently playing an important role in producing a significant amount of hydrocarbon. The Deccan Trap basaltic rocks form the basement of the Cambay Basin, India, and hold commercially producible hydrocarbon. In this study two wells drilled through fractured basalts are chosen for evaluating the lithology, porosity and oil saturation of the reservoir sections. Well logs, such as gamma ray, high resolution resistivity, litho density, compensated neutron and elemental capture spectroscopy, have been used in cross-plotting techniques for lithology and mineral identification. Formation micro imagery log data have been analysed to quantify the fractures and porosity in the fractured reservoirs for a well in the south Ahmedabad block of the Cambay Basin. The results of the analysis of two wells are presented and discussed and they are found to be in good agreement with geological and production data.