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.

Hydrocarbon derived from tight shale and other low-permeable reservoirs is an important and rapidly expanding front in energy development. Untapped hydrocarbon reserves can be exploited by fracturing these rocks using pressure-fracturing fluid. Different forms of fracturing fluids have been created, employed, and tested in fields for their efficiency and applicability. Aqueous polymer-based fracturing fluids and acid fracturing fluids are the most prominent class of field-employed fracturing fluids. Hydraulic fracturing procedures leave chemically complex fluids in the shale formation for at least 2 weeks. This gives the hydraulic fracturing fluid (HFF) plenty of chances to react with the formation at reservoir temperature and pressure. The interaction of fracturing fluid with the reservoir rocks and formation fluids has been discussed in this chapter. Furthermore, reaction kinetics, formation damage, and classes and mechanics of fracturing techniques have been elaborated.

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.

Sequestration of CO2 in geologic formations such as depleted oil reservoirs has emerged as one of the lead solutions to tackle greenhouse gas emissions to reduce pollution and global warming. Supercritical CO2 (sc-CO2) injection in oil reservoirs has proven to be useful as an enhanced oil recovery (EOR) technique along with the benefits of CO2 sequestration. In this study, a tortuous microscopic pore scale model was used to study and investigate the phenomena of water-alternating gas (WAG) and surfactant-alternating gas (SAG) with sc-CO2. The study scrutinizes the dynamics of the pore-level phenomenon in the multiphase WAG and SAG flows at the pore level in detail. Transient computational fluid dynamics (CFD) analysis was used to study the fluid flow characteristics of oil, water, and sc-CO2 at different reservoir pressure and temperature conditions in oil-wet conditions. Governing equations were coupled with EOS (Helmholtz free energy equation) to capture the viscous and intrinsic properties of sc-CO2 due to variations in pressure and temperature conditions. It was found that higher oil recovery does not necessarily indicate higher sc-CO2 sequestration and that temperature harms the displacement mechanism due to unfavorable mobility ratios. Comparing WAG and SAG for the first injection cycle, SAG showed a more diffused interface between displaced and displacing fluid. The additional oil recovery produced in patches was a result of pressure oscillations near the blind pores. Moreover, high vorticity promotes greater intermixing between the displacing and displaced fluid by increasing the rate of interface length. In SAG cases, faster sc-CO2 breakthroughs were observed due to reduced shear stress along the fluid interfaces, which resulted in higher sequestration values in a given time frame. The CO2 sequestration volume in SAG cases was found to be approximately 40% more than in WAG experiments. The study confirms that lower values of oil-water interfacial tension aids in faster and more efficient sequestration of sc-CO2 along with additional oil gain from a given reservoir.

The emerging desire for a sustainable approach toward energy production led the oil and gas industries to shift their interest from chemicals to microbial biosurfactants. As per the IEA report, global oil demands will rise by 7%, contributing 28% of total energy utilized. Developments in the field of microbiology have provided us with the solution of using microbes for the synthesis of biosurfactants. Microbial biosurfactants are classified as low–molecular weight (LMW) and high–molecular weight (HMW) biosurfactants. LMW biosurfactants are utilized to lower the interfacial tension, alter the rock wettability, and enhance oil recovery. These are found to improve oil recovery by up to 80%. HMW biosurfactants are generally used for the emulsification of fuels. This chapter focuses on providing an overview of different biosurfactants, emphasizing their role in enhancing the recovery of crude oil. In addition, additional applications of biosurfactants are discussed to reflect the significance of biosurfactants in the oil and gas industry.

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.