Jitendra S. Sangwai
Bio: Jitendra S. Sangwai is an academic researcher from Indian Institute of Technology Madras. The author has contributed to research in topic(s): Drilling fluid & Clathrate hydrate. The author has an hindex of 4, co-authored 5 publication(s) receiving 71 citation(s).
Abstract: The upsurge of drilling in shale and inaccessible reservoirs led to the emergence of Non Damaging Drilling Fluid (NDDF). Although this drilling fluid is non-invasive, the loss of rheological properties at high temperature poses a serious concern. In this study, we have investigated and quantified the enhancement in the performance of NDDF with the addition of zirconium oxide (ZrO2) nanoparticles (NPs) at 30, 60 and 80 °C. The synthesized ZrO2 NPs were of average 27 nm in size and were further characterized by Scanning Electron Microscope (SEM), X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FTIR) and Brunauer-Emmett-Teller (BET) adsorption methods. Varying concentrations, viz., 0.5, 0.8 and 1 wt% of ZrO2 NPs have been used to investigate their effect on various properties of NDDF. From the steady state rotational tests and viscoelastic measurements, it was observed that 1 wt% of ZrO2 NP NDDF had higher thermal stability in terms of viscosity and elasticity with a minimum filtrate loss. The ability to regain structural strength was also enhanced with the addition of ZrO2 NPs. Herschel Bulkley (HB) parameters from rheological measurements were calculated and optimized using genetic algorithm (GA) and were used to further carry out computational fluid dynamics (CFD) analysis. From CFD simulation results, it was observed that 1 wt% ZrO2 NP NDDF exhibited highest cutting carrying capacity as compared to 0 wt% (the base), 0.5 wt% and 0.8 wt% ZrO2 NP NDDF. Additionally, higher skewness in cutting deposition was observed for 1 wt% ZrO2 NP NDDF, limiting the possibility of bottom hole complications while drilling. This study is an important precursor for the oilfield application of nanoparticle based NDDF.
07 Mar 2020
TL;DR: The results suggest that the dominating mechanisms for oil recovery are wettability alteration, inherent interfacial tension reduction, and the effect of significant amount of microemulsions formation is rather trivial.
Abstract: Hypothesis Low salinity surfactant nanofluids have recently shown promising characteristics in wettability alteration of the silicate-based rock representative substrate and interfacial tension reduction of oil/aqueous phase interface. Pore level understanding of the physical processes entailed in this new class of low salinity injection fluids in oil-phase saturated real rock porous media is required, which has not been conceived yet. Experiments Thus, we investigate the oil recovery performance and possible mechanisms of oil recovery by the injection of low salinity surfactant (SDBS, 1.435 mM) aqueous solutions (with 0%, 0.01% and 0.1% (by weight) ZrO2 nanoparticles) into the oil phase saturated Doddington sandstone miniature core plugs. The designed experiment involves core flooding with X-ray transparent core-holder developed in-house and analysis/processing of the acquired image data. Findings The injection of low salinity surfactant nanofluids with 0.01% ZrO2 nanoparticles leads to maximum oil phase recovery. The results suggest that the dominating mechanisms for oil recovery are wettability alteration, inherent interfacial tension reduction, and the effect of significant amount of microemulsions formation is rather trivial. Low salinity effect, even in combination with surfactant, caused fines migrations (not reported earlier), is found to be significantly mitigated using nanoparticles. This new class of fluids may significantly enhance oil recovery.
Abstract: Information on the high pressure rheological properties of methane hydrate sediment slurry is an important precursor to understand their impact on the mechanical behaviour of host sediments during natural gas production from hydrate reservoirs. However, rheological analysis of gas hydrate slurries in the presence of natural sediments containing complex minerals and salts is not yet available in the open literature. The multiphase nature of hydrate systems is another challenge when it comes to the high pressure rheology study. Since, the conventional Couette geometry does not ensure proper mixing of solid, liquid and gas phases during hydrate formation and rheological measurements in a multiphase system, in this work, it has been modified to enhance the mixing capabilities. In this work, the rheological experiments on methane hydrate formation in sediment sample collected from Krishna Godavari Basin of offshore India have been performed. Rheological investigations were carried out using three different sed...
Abstract: Conventional bentonite-based drilling fluids have associated problems while drilling troublesome or high-temperature zone due to degradation of rheological properties and excessive fluid loss. Clay...
Abstract: In the oil and gas industry, upstream and downstream hydrocyclones are used extensively to separate heavy or dense particles from the formation water/reservoir fluids. These hydrocyclones, after a long period of operation, can fail as a result of wear-initiated leakage, thereby needing maintenance or replacement. A detailed investigation of this failure was carried out using computational fluid dynamics (CFD). One-way and two-way coupling of a discrete phase model was used along with the Reynolds stress turbulence model (RSM). Experimental studies were conducted to understand the flow dynamics within the hydrocyclone and to validate the computational model. Key findings, such as bifurcation of the inlet flow, local acceleration of fluid within the hydrocyclone, the impact of the sand drain pipe on fractional efficiency, and the impact of multiple particle sizes and density interactions on the degree of particle entrapment, are discussed in detail. The approach and results presented in this work provide useful insights and a systematic basis for improving the service life and separation efficiency of the hydrocyclone.
Abstract: Hypothesis Actualization of the hydrogen (H2) economy and decarbonization goals can be achieved with feasible large-scale H2 geo-storage. Geological formations are heterogeneous, and their wetting characteristics play a crucial role in the presence of H2, which controls the pore-scale distribution of the fluids and sealing capacities of caprocks. Organic acids are readily available in geo-storage formations in minute quantities, but they highly tend to increase the hydrophobicity of storage formations. However, there is a paucity of data on the effects of organic acid concentrations and types on the H2-wettability of caprock-representative minerals and their attendant structural trapping capacities. Experiment Geological formations contain organic acids in minute concentrations, with the alkyl chain length ranging from C4 to C26. To fully understand the wetting characteristics of H2 in a natural geological picture, we aged mica mineral surfaces as a representative of the caprock in varying concentrations of organic molecules (with varying numbers of carbon atoms, lignoceric acid C24, lauric acid C12, and hexanoic acid C6) for 7 days. To comprehend the wettability of the mica/H2/brine system, we employed a contact-angle procedure similar to that in natural geo-storage environments (25, 15, and 0.1 MPa and 323 K). Findings At the highest investigated pressure (25 MPa) and the highest concentration of lignoceric acid (10−2 mol/L), the mica surface became completely H2 wet with advancing ( θ a = 106.2°) and receding ( θ r = 97.3°) contact angles. The order of increasing θ a and θ r with increasing organic acid contaminations is as follows: lignoceric acid > lauric acid > hexanoic acid. The results suggest that H2 gas leakage through the caprock is possible in the presence of organic acids at higher physio-thermal conditions. The influence of organic contamination inherent at realistic geo-storage conditions should be considered to avoid the overprediction of structural trapping capacities and H2 containment security.
Abstract: Tight gas carbonate formations have enormous potential to meet the supply and demand of the ever-growing population. However, it is impossible to produce from these formations due to the reduced permeability and lower marginal porosity. Several methods have been used to extract unconventional tight gas from these reservoirs, including hydraulic fracturing and acidizing. However, field studies have demonstrated that these methods have environmental flaws and technical problems. Liquid nitrogen (LN2) fracturing is an effective stimulation technique that provides sudden thermal stress in the rock matrix, creating vivid fractures and improving the petro-physical potential. In this study, we acquired tight gas carbonate samples and thin sections of rock from the Laki limestone formation in the Lower Indus Basin, Pakistan, to experimentally quantify the effects of LN2 fracturing. Initially, these samples were characterized based on mineralogical (X-ray diffraction), petrography, and petro-physical (permeability and porosity) properties. Additionally, LK-18-06 Laki limestone rock samples were exposed to LN2 for different time intervals (30, 60, and 90 mins), and various techniques were applied to comprehend the effects of the LN2 before and after treatment, such as atomic force microscopy, scanning electron microscopy, energy-dispersive spectroscopy, nano-indentation, and petro-physical characterization. Our results reveal that the LN2 treatment was very effective and induced vivid fractures of up to 38 µm. The surface roughness increased from 275 to 946 nm, and indentation moduli significantly decreased due to the decreased compressibility of the rock matrix. Petro-physical measurements revealed that the porosity increased by 47% and that the permeability increased by 67% at an optimum LN2 treatment interval of 90 mins. This data can aid in an accurate assessment of LN2 fracturing for the better development of unconventional tight gas reservoirs.
Abstract: Common models used to describe rheological behavior of drilling fluids are built on pure viscous flow assumption. Full rheological characterization of drilling fluid under this assumption is not feasible since drilling fluids are viscoelastic materials and exhibit both elastic and viscous features. Gel strength development, yield stress value at near zero shear rates, and sag tendency in drilling fluids are the strong function of viscoelastic responses. Linear and nonlinear viscoelastic responses should be measured to provide complete viscoelastic analysis. Two water-based drilling fluids, sepiolite and bentonite drilling muds, each in four states, were subjected to testing using rheometer. Nonlinear viscoelastic parameters and their indications for both fluid systems were characterized for the first time. Large amplitude oscillation sweep tests were conducted as a function of strain and strain rate at four temperatures and frequencies. Stress response was decomposed through Fourier transform into elastic and viscous stress components. Lissajous-Bowditch loops were assessed as rheological fingerprints to detect the initiation of nonlinear region and the nature of nonlinearity. Results revealed that bentonite fluid systems provided stronger gel strength, a more stable network, and high mechanical stability compared to sepiolite fluid samples up to 50 °C. However, the sepiolite fluid systems outperformed at high temperatures (100 and 150 °C). The elastic nonlinear response was determined to be strain/strain rate softening, and the nonlinear viscous response was shear rate thinning at large strain rates for both fluid systems. Contrary to common knowledge found in literature (shear rate thinning), it was revealed that both fluid systems demonstrated shear rate thickening behavior at low to moderate strain rates. This finding is of importance in understanding gel strength development and evaluating sag tendency in drilling operations.
Abstract: A viscoelastic material exhibits both fluid (viscous) and solid (elastic) like properties simultaneously. The rheological behavior of drilling fluids is customarily measured under the assumption of pure viscous flow, yet they exhibit both viscous and elastic characteristics when subjected to deformation. Some imperative properties of drilling fluids such as gel strength, yield stress, and sag tendency at near-zero shear rate region are categorically under the influence of viscoelastic behavior and have not yet been completely understood due to the lack of appropriate measurement methods. Characterizing the complete rheological profile of material requires measuring linear and nonlinear viscoelastic responses at a wide range of stress/strain levels. The viscoelastic nonlinearity can be characterized under Large Amplitude Oscillatory Shear (LAOS) tests. This study presents a large amplitude oscillatory shear rheology investigation of two water-base (Lignosulfonate and KCl/polymer) and two oil-base (low and high temperature) drilling fluids each in three states; unweighted, weighted, and weighted-contaminated. The viscoelastic nonlinearities of four fluid samples were investigated experimentally as a function of strain amplitude and strain-rate space at different temperatures. The results were described using Lissajous-Bowditch (L-B) plots and local nonlinear viscoelastic dynamic moduli through an oscillatory shear cycle. Structural stability of fluid samples was also studied using the creep-recovery test. The nonlinear viscoelastic behavior of drilling fluids was comprehensively compared and distinguished to understand their nonlinear shear mechanism. As a result of the creep-recovery test at 150 °C, high-temperature oil base mud provided higher thermo-structural stability and zero shear viscosity than those of Lignosulfonate, KCl/polymer, and low-temperature oil-base muds. While the elastic nonlinearity was found to be strain/strain rate softening, the nonlinear viscous character was recorded as shear/shear rate thinning at large strain rates for all drilling fluid systems. Quite a different shear mechanism was detected at low and moderate strain rates. Shear rate thinning was found to be the dominant mechanism for all fluids except Lignosulfonate mud samples that demonstrated shear-thickening behavior at moderate strain rates at 25 °C. At high temperatures (100 °C and 150 °C), shear rate thickening followed by shear rate thinning behavior was governing mechanism under the low and moderate strain rates in all mud samples except KCl/polymer muds. An inverse behavior (shear rate thinning followed by shear rate thickening) was observed through low and moderate strain rates in KCl/polymer muds at 100 °C and 150 °C. Therefore, as revealed from the LAOS test results, shear rate thickening behavior at low to moderate strain rates is in contradiction of the commonly known shear thinning behavior for a drilling fluid undergoing viscous deformation. This finding explains the facts underlying some important properties of drilling fluids such as gel structure formation, hole cleaning ability, and sag tendency.
Author's H-index: 4