Jitendra Sangwai

Drilling operations in oil and gas industry are associated with issues such as pipe sticking, poor wellbore cleaning and high fluid loss. Mitigation of such problems in water-based drilling mud (WBM) necessitates the application of nanotechnology in improving their filtration and rheological characteristics. In the present work, an attempt has been made to analyze the effect of nanofluid prepared using copper oxide (CuO) nanoparticles (NPs) dispersed in chia seed solution on WBM characteristics. Therefore, three samples of chia seed based nanofluids are synthesized using two-step method by varying the concentration of CuO nanoparticle from 0.2 wt% to 0.6 wt%. The resulting nanofluids are then mixed with WBM to prepare Nanofluid enhanced Water based Drilling Mud (NFWBM). The synthesized nanofluids are then characterized for their stability and thermal decomposition respectively using Scanning Electron Microscope (SEM) and Thermo-Gravimetric Analyzer (TGA). The NFWBMs are then analyzed for rheological and filtrate-loss properties at different temperatures of 30 °C, 50 °C, 70 °C and 90 °C. The hot roll aging process is carried out at 90 °C for 16 h maintaining the pressure at 0.1 MPa. The analysis projected a significant enhancement in the thermal stability of the WBM, with a reduction in viscosity of about 61.7% at 90 °C, which is critically observed to recover back to a significant extent of about 14% for chia based 0.4 wt% CuO nanofluid enhanced WBM and 19% for chia based 0.6 wt% CuO nanofluid enhanced WBM. Such improvement is observed in the rheological properties post hot rolling too. Further, the API fluid loss is observed to reduce from 7.2 ml to 6.8 ml, 6 ml, and 4.8 ml, respectively, before hot rolling, while the same reduced from 12.4 ml 11.4 ml, 10.2 ml, and 9.4 ml, respectively, for chia based 0.2 wt%, 0.4 wt%, and 0.6 wt% of CuO nanofluid enhanced water based drilling muds (NFWBMs). The present study aids in the development of novel and green additives for water-based muds to enhance their properties.

Detailed studies on asphaltenes from Indian sources are scarce. In this study, nC7 asphaltenes were extracted from an atmospheric tower bottom and a low waxy crude oil using IP143-based method and characterised using elemental analysis, nuclear magnetic resonance, Fourier-transform infrared spectroscopy, matrix-assisted laser desorption-time of flight mass spectroscopy, X-ray diffraction, and scanning electron microscopy. Results show that both asphaltenes differ widely in structures and molecular weights. It was deduced that both asphaltenes might have formed from kerogen degradation process resulting in higher oxygen content. Lower molecular weight and structural parameters (NMR) of atmospheric tower bottom asphaltene could be due to degradation of aliphatic part during preheating before atmospheric distillation process. Although dispersed, the XRD derived aromaticity of petroleum asphaltenes seems to vary inversely with stacking height and average diameter of the aromatic sheets, possibly due to compact structure of the cluster resulting from decreased stack height.

Gas hydrates have been the nucleus of research from a sustainable engineering standpoint, considering their unique applications in a broad spectrum of scientific contexts. One such application is the sequestration of gaseous CO2 as solid hydrates under the seabed. Low temperature and high pressure are prevalent below the seabed, making it a thermodynamically feasible process. Furthermore, improved CO2 hydrate kinetics will facilitate technological development for carbon capture, storage, and sequestration. This study focuses on comprehending the CO2 hydrate kinetics with organic aliphatic amines, particularly methylamine, amylamine, and decylamine. Additives were tested in concentrations of 0.1, 1, and 5 wt % to meticulously comprehend their impact. A 300 mL stirred tank reactor was used for the investigations at 3.5 MPa and 274.55 K with pure water, which are the typical temperature and pressure conditions that one encounters in shallow subsea sediments. All additives showed considerable promotion in induction time, assuring faster CO2 hydrate nucleation. In addition, decylamine resulted in faster uptake of CO2 in our experiments compared to the other two additives. Hydrate dissociation studies up to 293.15 K were performed to assess the effect of the considered additives on CO2 hydrate dissociation. The decylamine system also delayed the gas release rate, showing better stability than the pure water system. This study also proposes a suitable well design for enhanced subsea CO2 sequestration as solid hydrates.

In this experimental work, three different types of nanofluids were evaluated for their stability using dynamic light scattering and particle morphological study using scanning electron microscopy. The nanofluids used in this study are zinc oxide (ZnO) nanoparticle in water and 5 wt% polyvinylpyrrolidone (PVP) as a dispersant, and ZnO with polyethylene glycol (PEG 600) and CuO with PEG 600 with 5 wt% PVP at different concentration of 0.1, 0.3 and 0.5 wt%. Thermal and electrical conductivities were determined by KD-2 Pro® and PC 700 Eutech®. The result shows better enhancement in the thermal and electrical conductivity in the ZnO+PVP+Water system, followed by the CuO+PVP+PEG and ZnO+PEG systems. The highest percentage enhancement in thermal conductivity found to be 35.5% of ZnO+ PVP+water systems. The thermal conductivity results were compared with a theoretical model and show good agreement with results predicted by the model. The proposed model of Nan et al. (1997) is based on a hypothesis regarding the physical mechanism in heat transfer for nanofluids. This study is expected to form the basis for the development of nanofluid-based technologies with PEG as the primary additive in the upstream oil and gas industry especially in gas hydrates and drilling technology.

A fundamental study on hydrate formation from an equimolar CO2-CH4 gas mixture has been carried out with two focal points: accelerating the kinetics of hydrate formation and enhancing the gas separation efficiency of the process. To this effect, the impact of inducing different hydrate structures from the same gas mixture by introducing suitable additives into the system has been investigated, and experiments are being carried out in a horizontal packed bed reactor at two different initial pressures, 3.5 and 5.0 MPa, to study the effect of driving forces on the kinetics of hydrate formation and the separation efficiency of the process. sH hydrate former cyclooctane (Cyclo-O) induces rapid nucleation of hydrate and also yields significant gas uptake in hydrates, 29.55% higher compared to the water system. This may be attributed to the simultaneous formation of sH and sI hydrates when Cyclo-O is present in the system. It was observed that the environmentally benign hydrophobic amino acid tryptophan in low concentration (1 wt %) can effectively accelerate the kinetics of hydrate formation, with 90% water to hydrate conversion being obtained within the first 30 min of hydrate formation. Further, the use of Cyclo-O and tryptophan together shows a synergistic effect, resulting in the highest gas uptake among all the systems studied. Although the problem of slow kinetics of hydrate formation from CO2-CH4 gas mixtures has been satisfactorily solved through this work, there are still significant strides that need to be made toward improving the separation efficiency of the process. The formation of the mixed hydrate is unable to return a satisfactorily high efficiency for gas separation.

Proper understanding of the interaction of individual components of crude oil with hydrate formation and dissociation is essential to design an effective mitigation strategy for hydrate blockage, especially in offshore flowlines. In this study, various isothermal methane hydrate formation and dissociation kinetics experiments have been carried out in oil-in-water dispersion systems to understand the effect of liquid hydrocarbons (such as n-heptane and toluene) and asphaltenes with varying concentrations at 8 MPa and 275.15 K. To correlate the results obtained from the kinetics experiments, solubility tests and interfacial tension measurements have also been carried out. It was observed that aromatic hydrocarbons (e.g., toluene) in the system led to less dissolution of methane gas as compared to alkanes (e.g., n-heptane). This, along with the more developed oil− water interface due to the lower density difference with water, made the system more vulnerable to hydrate formation, and it displayed secondary hydrate induction. The presence of asphaltenes in the oil−water system showed higher gas consumption during hydrate formation at lower concentrations, possibly due to flocculated asphaltene molecules at the oil−water interface acting as nucleation sites for hydrate formation. As the concentration of asphaltene increases, the growth of hydrate crystals is found to be limited, as more asphaltene molecules tend to restrict the gas diffusion toward the water phase, controlling the growth kinetics during hydrate formation. The hydrate dissociation experiments suggest that the presence of flocculated asphaltenes in the system has delayed the dissociation of methane hydrate crystals for some time. The findings of this study will help gain an insight into the interaction of asphaltene, alkanes, and aromatics on the kinetics of methane hydrate formation and dissociation suitable for flow assurance applications.

Hypothesis: The advanced low salinity aqueous formulations are yet to be validated as an injection fluid for enhanced oil recovery (EOR) from the carbonate reservoirs and CO2 geosequestration. Interaction of various ionic species present in the novel low salinity surfactant nanofluids with scCO2/CO2 saturated aqueous phase interface and at the interface of CO2 saturated aqueous phase/mixed wet (with CO2 and Decane) limestone surface at the conditions of low salinity at reservoir conditions are to yet to be understood. Experiments: This study, carried out for the first time in low salinity at scCO2 loading conditions at 20 MPa pressure and 343 K temperature, comprises of wettability study of the limestone surface by aqueous phase contact angle measurements using ZrO2 nanoparticles (in the concentration range of 100–2000 mg/L) and 0.82 mM Hexadecyltrimethylammonium bromide (CTAB) surfactant. Molecular dynamics simulations results were used to understand the underlying mechanism of wettability alteration and interfacial tension (IFT) change. Findings: This study reveals that a low dosage (100 mg/L) of ZrO2 nanoparticles forming ZrO2-CTAB nano-complexes helps in wettability alteration of the rock surface to more water-wetting state; certain ionic species augment this effect when used in appropriate concentration. Also, these nano-complexes helps in scCO2/CO2 saturated aqueous phase IFT reduction. This study can be used to design advanced low salinity injection fluids for water alternating gas injection for EOR and CO2 geosequestration projects.

The present study investigates the effect of l-tryptophan on the kinetics of CO2-CH4 (50:50 mol %) hydrate formation in a gas-water system by employing a stirred tank reactor. The concentration of tryptophan was varied in the range from 0.01 to 1 wt %, and its impact on the kinetics of CO2-CH4 (50:50 mol %) hydrate formation was investigated at 5.0 MPa and 274.15 K. The time required for 90% completion of hydrate formation was reduced from 100.89 ± 11.03 min to 19.11 ± 1.68 min when the tryptophan concentration increased from 0.01 wt % to 1 wt %. The gas uptake achieved using 1 wt % tryptophan (0.1045 ± 0.0023 mol per mol) was approximately 5 times higher than that of 0.01 wt % tryptophan (0.0227 ± 0.0017 mol per mol). Thus, the addition of tryptophan resulted in rapid and extensive hydrate formation. The hydrate formation kinetics were assessed based on gas uptake of hydrate growth, t90 time, and rate of gas uptake of hydrate growth, and 1 wt % tryptophan concentration was found to be the optimum concentration in the gas-water system. Further, experiments were performed to understand the kinetics of CO2-CH4 (50:50 mol %) hydrate formation by inducing sH hydrate using 2.86 mol % cyclooctane (Cyclo-O), a thermodynamic promoter in a gas-liquid hydrocarbon (LHC)-water system at 5.0 MPa and 274.15 K. After that, the synergistic effect using Cyclo-O with 0.1 and 1 wt % tryptophan separately was evaluated. Application of 1 wt % tryptophan helps in crossing the resistance of immiscible Cyclo-O phase, resulting in higher gas uptake of hydrate growth compared to 0.1 wt % tryptophan with Cyclo-O. Visual macroscopic morphology observations coupled with kinetic experiments were also performed for gas-water and gas-LHC-water systems. Visual observations showed that the hydrate could form and grow below the gas-liquid interface for experiments conducted with (i) pure water, (ii) water and 0.01 wt % tryptophan, and (iii) water and 2.86 mol % Cyclo-O, whereas the experiments with tryptophan concentration > 0.01 wt % in the gas-water system and with tryptophan concentration ≥ 0.1 wt % with Cyclo-O in gas-LHC-water resulted in hydrate formation above the gas-liquid interface. Thus, the capability of tryptophan in forming hydrates above the interface was attributed to different hydrate morphology; an altered morphology resulted in a capillary effect through which the mass transfer of hydrate-forming components improved.

Recently, carbon capture, utilization, and storage (CCUS) with enhanced oil recovery (EOR) have gained a significant traction in an attempt to reduce greenhouse gas emissions. Information on pore-scale CO2 fluid behavior is vital for efficient geo-sequestration and EOR. This study scrutinizes the behavior of supercritical CO2 (sc-CO2) under different reservoir temperature and pressure conditions through computational fluid dynamics (CFD) analysis, applying it to light and heavy crude oil reservoirs. The effects of reservoir pressure (20 MPa and 40 MPa), reservoir temperature (323 K and 353 K), injection velocities (0.005 m/s, 0.001 m/s, and 0.0005 m/s), and in situ oil properties (835.3 kg/m3 and 984 kg/m3) have been considered as control variables. This study couples the Helmholtz free energy equation (equation of state) to consider the changes in physical properties of sc-CO2 owing to variations in reservoir pressure and temperature conditions. It has been found that the sc-CO2 sequestration is more efficient in the case of light oil than heavy oil reservoirs. Notably, an increase in temperature and pressure does not affect the trend of sc-CO2 breakthrough or oil recovery in the case of a reservoir bearing light oil. For heavy oil reservoirs with high pressures, sc-CO2 sequestration or oil recovery was higher due to the significant increase in density and viscosity of sc-CO2. Quantitative analysis showed that the stabilizing factor (ε) appreciably varies for light oil at low velocities while higher sensitivity was displayed for heavy oil at high velocities. Graphical abstract: [Figure not available: see fulltext.]

Wettability of surfaces remains of paramount importance for understanding various natural and artificial colloidal and interfacial phenomena at various length and time scales. One of the problems discussed in this work is the wettability alteration of a three-phase system comprising high salinity brine as the aqueous phase, Doddington sandstone as porous rock, and decane as the nonaqueous phase liquid. The study utilizes the technique of in situ contact angle measurements of the several 2D projections of the identified 3D oil phase droplets from the 3D images of the saturated sandstone miniature core plugs obtained by X-ray microcomputed tomography (micro-CT). Earlier works that utilize in situ contact angles measurements were carried out for a single plane. The saturated rock samples were scanned at initial saturation conditions and after aging for 21 days. This study at ambient conditions reveals that it is possible to change the initially intermediate water-wet conditions of the sandstone rock surface to a weakly water wetting state on aging by alkanes using induced polarization at the interface. The study adds to the understanding of initial wettability conditions as well as the oil migration process of the paraffinic oil-bearing sandstone reservoirs. Further, it complements the knowledge of the wettability alteration of the rock surface due to chemisorption, usually done by nonrepresentative technique of silanization of rock surface in experimental investigations.