Effect of decreased contrast injection flow rate on aortic enhancement in 80-KV peak CT with contrast dose reduction

Background Effect of decreased injection flow rate of contrast agent at the same iodine dose and delivery rate on aortic enhancement has not been clearly elucidated. Purpose To evaluate the effect of decreased injection flow rate of contrast agent on aortic peak enhancement in a dynamic flow phantom and on aortic enhancement in clinical dynamic 80-kVp computed tomography (CT) with contrast dose reduction. Material and Methods In the dynamic flow phantom experiment, the effect of a decreased injection flow rate at the same total iodine dose and delivery rate on simulated aortic peak enhancement was evaluated. In the clinical retrospective study, we searched 312 patients with renal dysfunction who underwent an 80-kVp abdominal dynamic CT with 40% reduction of contrast agent from a standard 120-kVp protocol and measured the aortic enhancement at the level of the hepatic hilum. Independent predictors for aortic enhancement were determined by multiple linear regression analysis, and after adjustment of significant predictors, independent variables for acquiring optimal aortic enhancement, ≥300 HU, were determined by multiple logistic regression analysis. Results In the phantom experiment, decreased flow rate showed a significant but small descent effect (6%–9%) on simulated aortic peak enhancement. In the multiple linear regression analysis, only age was an independent predictor of aortic enhancement; there was no independent predictor for optimal age-adjusted aortic enhancement of ≥300 HU. Conclusions Decreased injection flow rate had a small influence on aortic enhancement in vitro but had no significant effect on the aortic enhancement in clinical dynamic 80-kVp CT.

Interrelationship of Capillary Number, Interfacial Tension, Injection Flow Rate and Temperature by Surfactant Flooding for Oil-wet Carbonate Reservoirs

After water flooding in carbonate reservoirs, a significant fraction of the original oil as remaining oil is left in the swept zone. The remaining oil in the pore, trapped by viscous and capillary forces, is to target for improved and enhanced oil recovery. The mobilization of remaining oil can be predicted by a dimensionless parameter called capillary number. The interfacial tension and injection flow rate strongly affect the capillary number. Unfortunately, the interrelationship between capillary number, interfacial tension, injection flow rate, and the temperature has been poorly studied for carbonate reservoirs. This paper focuses on studying the remaining oil saturations at different orders of magnitude capillary numbers related to interfacial tension, injection flow rate, and temperature by seawater and surfactant flooding. Several core flooding experiments were performed by changing the injection rate and surfactant concentrations at evaluated conditions. Four displacement experiments of seawater/oil and surfactant solution/oil were performed using oil-wet carbonate cores to obtain the relationship between the residual oil saturation vs. the capillary number. The surfactant flooding experiments with different concentrations of 0.01 and 0.2 wt% were conducted when the remaining oil saturation was reached after water flooding. Three core flooding experiments were conducted at ambient conditions, and one was under evaluated conditions of a temperature of 100° and pore pressure of 3200 psi. Several injection rates were selected to experiment with a 0.2 wt% surfactant solution, which is to study the effect of injection rate on the capillary number and residual oil saturation. The experimental findings show that some remaining oil can be recovered from oil-wet carbonate cores if the capillary number increases by a critical Nc =2.1E-05 by surfactant flooding at reservoir conditions. After water flooding, the remaining oil saturation was decreased from 51% to 16% with 0.01wt% surfactant flooding. The reduction of interfacial tension from 6.77dyne/cm to 0.017dyne/cm led to an increased capillary number. It decreased the remaining oil saturation by about 5% OOIP when the capillary number increases three magnitudes. The effect of temperature and injection rate on the capillary number was observed based on experimental displacement results. Compared with results between the ambient and specified conditions, the effect of temperature on the capillary number is significant. Under the same capillary number, the remaining oil recovered by surfactant flooding at HPHT conditions was higher than that at ambient conditions. Also, the effect of the injection flow rate on the capillary number was observed by 0.2wt % surfactant flooding for all experiments. The capillary number increased with an increase in the injection rate for both ambient and evaluated conditions. This paper provides valuable results to evaluate the interrelationship between remaining oil and capillary numbers by surfactant flooding and design field application for oil-wet carbonate reservoirs.

Isolation of hydrodynamic parameters for the fibre length attrition in injection-moulded short-fibre polymer composites

A comprehensive study of the fibre breakage mechanisms during mould filling in injection moulding of short-fibre polymer composites requires the isolation of the main parameters promoting fibre length attrition. In this work, hydrodynamic parameters such as injection flow rate and residence time in the range of injection moulding were isolated, and their effect on fibre length attrition was studied. Fibre breakage was quantified by means of a capillary rheometer attached to an injection moulding machine minimising fibre-equipment interactions. Fibre breakage increased linearly as a function of injection flow rate in the range of 30–120 cm3.s−1. It was also found that residence time in the order of milliseconds had a significant effect on fibre breakage. The results shown that longer fibres had less breakage probability, which contradicts the buckling failure theory for brittle fibres in a simple shear flow. This result was attributed to the similar rotation period of the fibres in comparison with the test residence times.

Predictive Modelling of CO2 Injectivity Impairment due to Salt Precipitation and Fines Migration During Sequestration

Recent studies indicated that reactive interactions between carbon dioxide (CO2), brine, and rock during CO2 sequestration can cause salt precipitation and fines migration. These mechanisms can severely impair the permeability of sandstone which directly affect the injectivity of supercritical CO2 (scCO2). Previous CO2 injectivity change models are ascribed by porosity change due to salt precipitation without considering the alteration contributed by the migration of particles. Therefore, this paper presents the application of response surface methodology to predict the CO2 injectivity change resulting from the combination of salt precipitation and fines migration. The impacts of independent and combined interactions between CO2, brine, and rock parameters were also evaluated by injecting scCO2 into brine saturated sandstone. The core samples were saturated with NaCl brine with salinity between 6,000 ppm to 100,000 ppm. The 0.1, 0.3, and 0.5 wt.% of different-sized hydrophilic silicon dioxide particles (0.005, 0.015, and 0.060 μm) were added to evaluate the effect of fines migration on CO2 injectivity alteration. The pressure drop profiles were recorded throughout the injection process and the CO2 injectivity alteration was represented by the ratio between the initial and final injectivity. The experimental results showed that brine salinity has a greater individual influence on permeability reduction as compared to the influence of particles (jamming ratio and particle concentration) and scCO2 injection flow rate. Moreover, the presence of both fines migration and salt precipitation during CO2 injection was also found to intensify the permeability reduction by 10%, and reaching up to threefold with increasing brine salinity and particle size. The most significant reductions in permeability were observed at higher brine salinities, as more salts are being precipitated out which, in turn, reduces the available pore spaces and leads to a higher jamming ratio. Thus, more particles were blocked and plugged especially at the slimmer pore throats. Based on comprehensive 45 core flooding experimental data, the newly developed model was able to capture a precise correlation between four input variables (brine salinity, injection flow rate, jamming ratio, and particle concentration) and CO2 injectivity changes. The relationship was also statistically validated with reported data from five case studies.

Seismic Response to Injection Well Stimulation in a High-Temperature, High-Permeability Reservoir

©2019. American Geophysical Union. All Rights Reserved. Fluid injection into the Earth's crust can induce seismic events that cause damage to local infrastructure but also offer valuable insight into seismogenesis. The factors that influence the magnitude, location, and number of induced events remain poorly understood but include injection flow rate and pressure as well as reservoir temperature and permeability. The relationship between injection parameters and injection-induced seismicity in high-temperature, high-permeability reservoirs has not been extensively studied. Here we focus on the Ngatamariki geothermal field in the central Taupō Volcanic Zone, New Zealand, where three stimulation/injection tests have occurred since 2012. We present a catalog of seismicity from 2012 to 2015 created using a matched-filter detection technique. We analyze the stress state in the reservoir during the injection tests from first motion-derived focal mechanisms, yielding an average direction of maximum horizontal compressive stress (SHmax) consistent with the regional NE-SW trend. However, there is significant variation in the direction of maximum compressive stress (σ1), which may reflect geological differences between wells. We use the ratio of injection flow rate to overpressure, referred to as injectivity index, as a proxy for near-well permeability and compare changes in injectivity index to spatiotemporal characteristics of seismicity accompanying each test. Observed increases in injectivity index are generally poorly correlated with seismicity, suggesting that the locations of microearthquakes are not coincident with the zone of stimulation (i.e., increased permeability). Our findings augment a growing body of work suggesting that aseismic opening or slip, rather than seismic shear, is the active process driving well stimulation in many environments.

Seismic Response to Injection Well Stimulation in a High-Temperature, High-Permeability Reservoir

©2019. American Geophysical Union. All Rights Reserved. Fluid injection into the Earth's crust can induce seismic events that cause damage to local infrastructure but also offer valuable insight into seismogenesis. The factors that influence the magnitude, location, and number of induced events remain poorly understood but include injection flow rate and pressure as well as reservoir temperature and permeability. The relationship between injection parameters and injection-induced seismicity in high-temperature, high-permeability reservoirs has not been extensively studied. Here we focus on the Ngatamariki geothermal field in the central Taupō Volcanic Zone, New Zealand, where three stimulation/injection tests have occurred since 2012. We present a catalog of seismicity from 2012 to 2015 created using a matched-filter detection technique. We analyze the stress state in the reservoir during the injection tests from first motion-derived focal mechanisms, yielding an average direction of maximum horizontal compressive stress (SHmax) consistent with the regional NE-SW trend. However, there is significant variation in the direction of maximum compressive stress (σ1), which may reflect geological differences between wells. We use the ratio of injection flow rate to overpressure, referred to as injectivity index, as a proxy for near-well permeability and compare changes in injectivity index to spatiotemporal characteristics of seismicity accompanying each test. Observed increases in injectivity index are generally poorly correlated with seismicity, suggesting that the locations of microearthquakes are not coincident with the zone of stimulation (i.e., increased permeability). Our findings augment a growing body of work suggesting that aseismic opening or slip, rather than seismic shear, is the active process driving well stimulation in many environments.

Investigation of Hydraulic Performance Based on Response Surface Methodology for an Agricultural Chemigation Proportional Injector

Injectors are key pieces of equipment for chemigation systems, and their hydraulic performance has a significant effect on chemigation systems and crops. In order to investigate the influence of different working parameters on hydraulic performance for a water-powered proportional injector (PI), three key parameters of inlet and injection flow rate were researched using a one-factor experimental design method. The regression equations between different factors and response variables were established through a response surface method based on one-factor experimental results. Lastly, a mathematical model of the actual injection ratio was established. Some experiments under different, randomly selected parameter combinations were carried out to verify the prediction precision of the mathematical mode. The results showed that the injection flow rate increased first within the differential pressure of 0.05 to 0.10 MPa and then tended towards stability with increasing differential pressure. The injection flow rate decreased by increasing the viscosity and the change in the injection flow rate was small enough when the viscosity was greater than 500 mPa·s. The impact factors, in order of significance, for inlet flow rate were differential pressure, viscosity of injection liquid and setting injection ratio. The impact factors, in order of significance, for injection flow rate were viscosity of injection liquid, setting injection ratio and differential pressure. The regressive model for predicting the actual injection ratio was validated using an experiment and the relative deviation between calculated value and tested value was less than 5.98%, which indicated that the mathematical model had high credibility.