Shubham Saraf

Bio: Shubham Saraf is an academic researcher from Pandit Deendayal Petroleum University. The author has contributed to research in topics: Oil shale & Enhanced oil recovery. The author has an hindex of 1, co-authored 2 publications receiving 8 citations.

A review on pore-scale modeling and CT scan technique to characterize the trapped carbon dioxide in impermeable reservoir rocks during sequestration

Abstract: Global warming is increasing at a perpetual rate due to the emission of greenhouse gases in recent years. This spectacle has been mainly caused by the increase of carbon dioxide (CO2) in the environment. It is in need to find a path to reduce the greenhouse gases along with the additional benefit of energy demand in a sustainable way. A favorable long-term way out to mitigate global warming is to inject CO2 into geological formations of oil fields to achieve a goal of a combination of CO2 sequestration and enhanced oil recovery by CO2 flooding. Understanding the mechanism of CO2 sequestration under impermeable rock formation requires the knowledge of the pore-scale modeling concept. This review article provides an overview of pore-scale modeling and micro-CT scan imaging technique for CO2 sequestration including a background of basic concepts related to storage, CO2 enhanced oil recovery, simulators used, and storage estimation. Trapping mechanisms, geological description of the formation for CO2 sequestration, and reactions that have taken place during the trapping in underground formation are also discussed elaborately. Macro-scale and pore-scale modeling are depicted based on the current literature available. This review also presents petrophysical data that comes from the pore network modeling of CO2-brine pore structure for the formation of carbon-containing sandstone reservoirs. A discussion on the challenges of CO2 sequestration and modeling in pore-scale is also furnished to point out the problems and solutions in near future. Finally, the prospect of CO2 sequestration and pore-scale modeling are described for its uncountable value in greenhouse gas reduction from the environment.

Estimation of Porosity and Pore size distribution from Scanning Electron Microscope image data of Shale samples: A case study on Jhuran formation of Kachchh Basin, India.

Abstract: The work is aimed at estimating the porosity of shale from the Jhuran formation (Kachchh Basin) through non-destructive technique. Shale is a sedimentary rock formed by compaction of fine grained s...

Perspectives of Foam Generation Techniques and Future Directions of Nanoparticle-Stabilized CO2 Foam for Enhanced Oil Recovery

Abstract: Global demand for energy is increasing day by day rapidly as a result of the population, industrial, and economic growth of developing countries, especially in emerging market economies. Hence, to meet this growing and continuing global crude oil demand, innovative enhanced oil recovery (EOR) techniques are required to emerge, and currently, implemented techniques need to be revisited and optimized to recover more residual oil trapped in the reservoirs. Among different chemicals, foam has good mobility control in the oil recovery method. Nowadays, the study on the stability of foam is an utmost interest for petroleum engineers to find a way to obtain stable foam for application in EOR. In this review, the basics of foam and its preparations, properties, application, and some special applications mainly in the oil industry have been depicted to convey an idea of the degree of foam research in EOR. Basically, this review will provide a detailed discussion on the applications of foam in oil recovery and some short ideas that can be applied in the near future for nanoparticle (NP)-assisted stable CO2 foam flooding in EOR. Increasing the NP concentration initially improved foam stability because a higher number of NPs participated in strengthening the gas bubble and initially increased oil recovery as a result of the formation of more stable foam. The polymer-coated, nanoclay–surfactant-stabilized foam and surface-modified silica nanoparticles have exceptional foaming ability and foam stability at high temperatures, making them suitable for the production from heavy oil reservoirs. Some other nanoparticles, like Al2O3, ZrO2, TiO2, Fe2O3, and NiO, have also been used for enhancing foam stability by preventing liquid drainage from lamella. Also, NP-stabilized CO2 foam flooding can enhance oil recovery by 10–15% after secondary recovery by creating a more homogeneous gas front for better mobility control.

Dewetting of silica surfaces upon reactions with supercritical CO2 and brine: Pore-scale studies in micromodels - eScholarship

Abstract: Wettability of reservoir minerals and rocks is a critical factor controlling CO(2) mobility, residual trapping, and safe-storage in geologic carbon sequestration, and currently is the factor imparting the greatest uncertainty in predicting capillary behavior in porous media. Very little information on wettability in supercritical CO(2) (scCO(2))-mineral-brine systems is available. We studied pore-scale wettability and wettability alteration in scCO(2)-silica-brine systems using engineered micromodels (transparent pore networks), at 8.5 MPa and 45 °C, over a wide range of NaCl concentrations up to 5.0 M. Dewetting of silica surfaces upon reactions with scCO(2) was observed through water film thinning, water droplet formation, and contact angle increases within single pores. The brine contact angles increased from initial values near 0° up to 80° with larger increases under higher ionic strength conditions. Given the abundance of silica surfaces in reservoirs and caprocks, these results indicate that CO(2) induced dewetting may have important consequences on CO(2) sequestration including reducing capillary entry pressure, and altering quantities of CO(2) residual trapping, relative permeability, and caprock integrity.

Simulating the Cranfield Geological Carbon Sequestration Project with High-Resolution Static Models and an Accurate Equation of State

Abstract: In this study, a field-scale carbon dioxide (CO2) injection pilot project was conducted as part of the Southeast Regional Sequestration Partnership (SECARB) at Cranfield, Mississippi. We present higher-order finite element simulations of the compositional two-phase CO2-brine flow and transport during the experiment. High- resolution static models of the formation geology in the Detailed Area Study (DAS) located below the oil- water contact (brine saturated) are used to capture the impact of connected flow paths on breakthrough times in two observation wells. Phase behavior is described by the cubic-plus-association (CPA) equation of state, which takes into account the polar nature of water molecules. Parameter studies are performed to investigate the importance of Fickian diffusion, permeability heterogeneity, relative permeabilities, and capillarity. Simulation results for the pressure response in the injection well and the CO2 breakthrough times at the observation wells show good agreement with the field data. For the high injection rates and short duration of the experiment, diffusion is relatively unimportant (high P clet numbers), while relative permeabilities have a profound impact on the pressure response. High-permeability pathways, created by fluvial deposits, strongly affect the CO2 transport and highlight the importance of properly characterizing the formation heterogeneity in future carbon sequestrationmore » projects.« less

Quartz Crystal Microbalances Functionalized with Citric Acid-Doped Polyvinyl Acetate Nanofibers for Ammonia Sensing

Abstract: We fabricated highly sensitive and selective ammonia gas sensors based on quartz crystal microbalance (QCM) platforms that were functionalized with electrospun polyvinyl acetate (PVAc) nanofibers a...

Challenges in modeling unstable two-phase flow experiments in porous micromodels

Abstract: The simulation of unstable invasion patterns in porous media flow is very challenging because small perturbations are amplified, so that slight differences in geometry or initial conditions result in significantly different invasion structures at later times. We present a detailed comparison of pore-scale simulations and experiments for unstable primary drainage in porous micromodels. The porous media consist of Hele-Shaw cells containing cylindrical obstacles. By means of soft lithography, we have constructed two experimental flow cells, with different degrees of heterogeneity in the grain size distribution. As the defending (wetting) fluid is the most viscous, the interface is destabilized by viscous forces, which promote the formation of preferential flow paths in the form of a branched finger structure. We model the experiments by solving the Navier-Stokes equations for mass and momentum conservation in the discretized pore space and employ the Volume of Fluid (VOF) method to track the evolution of the interface. We test different numerical models (a 2-D vertical integrated model and a full-3-D model) and different initial conditions, studying their impact on the simulated spatial distributions of the fluid phases. To assess the ability of the numerical model to reproduce unstable displacement, we compare several statistical and deterministic indicators. We demonstrate the impact of three main sources of error: (i) the uncertainty on the pore space geometry, (ii) the fact that the initial phase configuration cannot be known with an arbitrarily small accuracy, and (iii) three-dimensional effects. Although the unstable nature of the flow regime leads to different invasion structures due to small discrepancies between the experimental setup and the numerical model, a pore-by-pore comparison shows an overall satisfactory match between simulations and experiments. Moreover, all statistical indicators used to characterize the invasion structures are in excellent agreement. This validates the modeling approach, which can be used to complement experimental observations with information about quantities that are difficult or impossible to measure, such as the pressure and velocity fields in the two fluid phases.