With
a constant upsurge in energy demand, production from depleted
and harsh reservoirs through enhanced oil recovery techniques (EOR)
has significantly increased. Among many EOR techniques, chemical EOR
(cEOR) is one of the most widely used methods of oil extraction. Surfactants
used in cEOR are instrumental in reducing interfacial tension (IFT)
and altering the wettability of rock, which leads to additional oil
recovery. This review draws attention to detail on surfactants from
fundamentals to field scale. Properties of surfactants like phase
behaviors, critical micelle concentration (CMC), hydrophilic–lipophilic
balance and deviation, zeta potential, and their importance are discussed
in depth. The presence of a saline environment, polymer, cosurfactant,
and other factors affecting the performance of surfactant during the
cEOR process are also elaborated. Key findings on surfactant adsorption
on reservoir rock with other influencing aspects have also been reported
in this study. Types of surfactants, from basic to the likes of polymeric,
viscoelastic, Gemini, natural, and their effects on oil recoveries
have been analyzed and compared. Special emphasis on emerging aids
for surfactant flooding such as applications of nanotechnology, use
amphoteric Janus particles, and synergies of surfactant–low
salinity water flooding, along with their mechanisms and recent advances
have been thoroughly duscussed. Lastly, the review delineates discerning
criteria for the selection of surfactants, reviews recent field applications,
and outlines the challenges that the industry faces while implementing
surfactant cEOR. It has been found that exhaustive studies have been
conducted on sandstones with success. However, extreme temperature
and saline conditions in the case of carbonate reservoirs limit the
applicability of surfactants, and the pursuit to accomplish its efficacy
continues.
The increase in hydrocarbon production from problematic production zones having high fluid loss and formation damage has led to the emergence of non-damaging drilling fluids (NDDF). Recently, nanotechnology has found a wide array of applications in the oil and gas industry. Most applications of nanotechnology and enhancement in properties of drilling fluids are restricted to bentonite, xanthan gum and a few oil-based mud. In this study, the effects of silica and copper oxide nanoparticles on polyamine-based NDDF and conventional bentonite-based drilling fluids (BDF) were investigated. Silica nanoparticles were prepared using sol-gel method, and copper oxide nanoparticles were synthesized using co-precipitation method. Nano-based drilling fluids were prepared by dispersing nanoparticles in concentrations of 0.5%, 0.8% and 1% by weight. Furthermore, testing of these nano-based drilling fluids was conducted by measuring specific gravity, pH, rheological properties and filtrate loss at surface temperature (room temperature) and then aging it at bottom-hole temperature (80 °C). The addition of silica and copper oxide nanoparticles to both the drilling fluids did not show much effect on pH and specific gravity. Addition of 0.5% concentration of silica nanoparticles in NDDF showed least degradation in rheological properties compared to other fluids. It showed reduction in filtrate loss by 31%. Moreover, silica nanoparticles in conjunction with BDF acted as a mud thinner showing a decrease in viscosity and yield point. On the contrary, when used with NDDFs, silica nanoparticles acted as a mud thickener. Copper oxide nanoparticles behaved as a thinner in both the drilling fluids with a highest reduction in plastic viscosity of 24% for 0.8% of copper oxide nanoparticle in BDF. Thinning properties were enhanced as the doping concentrations of copper oxide nanoparticles increased; however, the fluid loss controlling ability decreased except for 0.5% concentration by 31% and 24% when used with both the drilling fluids. Additionally, optimal Herschel-Bulkley parameters have been determined by using genetic algorithm to minimize the function of sum of squared errors between observed values and model equation.
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.
Climate change has been linked to industrial and commercial activities caused by exploitation of fossil fuels for energy needs for over a century now. A significant rise in greenhouse gas (GHG) emissions, majorly CO 2 , has been reported in the last few decades. Global climate change necessitates mitigation of atmospheric CO 2 levels to suitable margins using CO 2 capture mechanisms. Direct air capture (DAC) technology is the most efficient way to mitigate or reduce greenhouse emissions by capturing carbon dioxide directly from the atmospheric air. It is imperative that DAC technology be ramped up quickly in order to meet the climate goal to reduce global temperature rise below 2 °C in the next 30 years. This review focuses on the specifics of various techniques, pilot projects, and commercial facilities for DAC technology deployment. DAC has seen substantial technical improvement in recent years, with commercial firms already functioning in the industry with significant upmarket potential. There are about 19 DAC plants in operation across the world, absorbing around 0.01 Mt CO 2 /year. This review article discusses the various DAC technologies used by the companies, future potential, life cycle assessment, as well as the economic viability of worldwide installation of these facilities. The paper provides details on the application of various sorbents including nanomaterials for current advances in DAC. Lastly, the outlook and perspectives are also presented with the concluding remarks.
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