A downhole electric heater, which reduces heat loss along a heat insulation pipe, is a key apparatus used to ignite oil shale underground. Downhole heaters working together with packers can improve the heating efficiency of high-temperature gases, while different packer locations will directly affect the external air temperature of the heater shell and, subsequently, the performance and total cost of the downhole heaters. A device was developed to simulate the external conditions of heater shells at different packer locations. Then, the effects of external air temperature on the performance of a downhole heater with pitches of 50, 160, and 210 mm were experimentally studied. In the test, results indicated that the heater with a packer at its outlet had an accelerated heating rate in the initial stage and decreased temperature in the final stage. Additionally, the lowest heating rod surface temperature and highest comprehensive performance were achieved with minimal irreversible loss and lower total cost when using a downhole electric heater with a packer set at its outlet. In addition, the downhole electric heater with a helical pitch of 50 mm and a packer at its outlet was more effective than other schemes in the high Reynolds number region. These findings are beneficial for shortening the oil production time in oil shale in situ pyrolysis and heavy oil thermal recovery.
As an emerging technique, carbon dioxide capture and storage (CCS) is to mitigate greenhouse gas emissions. Deep saline aquifers are increasingly considered because of their wide distributionlarge thicknesslarge capacity. A proper understanding of displacement character of supercritical CO2-brine system is significant in knowing CO2 Injectivity, migration and trapping, and in assessing the safety and suitability of reservoir site. CO2-brine system is multi-phase flow system, the mobility is related to interfacial tensioncapillary pressurerelative permeability. The experiments took into account the impact factors such as interfacial tensioncapillary pressurerelative permeability, foreign indoor experiments of CO2-brine system are analyzed and summarized, a brief description of indoor experiments of our country and future work are given.
Several retrofillings have been performed by different utilities in China. However, there is still insufficient understanding of the retrofilling procedures for minimising residual mineral oil and on the effect of the temperature rise of transformers. Following new detailed procedures, an out‐of‐service S11‐M‐315/10 (10 kV 315 kVA) and a new S13‐M‐400/10 (10 kV 400 kVA) distribution transformers were selected to retrofill their mineral oil with FR3, a soybean‐based natural ester. A method was proposed to predict the residual mineral oil content, which uses the kinematic viscosity at 60°C. This method fills a gap in the testing of residual mineral oil content. The mass ratios of residual mineral oil were 1.24% for the S11‐M‐315/10 transformer and 2.05% for the S13‐M‐400/10 transformer, based on the procedures in this study. The fire point of the mixed oil after retrofilling was 352°C, which meets the K‐class less‐flammable requirements, indicating a proper control of residual mineral oil. After retrofilling, the time of reaching the limits of the 1.5 times rated load was 30% longer than that of the mineral oil transformer. Two retrofilled transformers have been operating in good conditions since November 2019 for the S11‐M‐315/10 transformer and December 2020 for the S13‐M‐400/10 transformer.
Solvent-Assisted Steam-Assisted Gravity Drainage (SA-SAGD) is invented by adding solvent into the injection stream. However, the high cost of the solvent makes it necessary to ensure a high efficiency of solvent transportation from the long-horizontal wellbore to the chamber edge. In this study, a novel model considering the wellbore/chamber coupling effects is established, which can accurately evaluate the performance of SA-SAGD. First, governing equations for mass flow in the wellbore are built on the basis of the mass and momentum balance determined by coupling the wellbore and steam chamber. Besides, implicit equations for phase changes were derived according to the heat-mass transfer between wellbore and chamber. Second, the model for oil flow rate in the chamber rising stage is derived by the chamber height identified by the variation in thermo-physical properties of solvent and steam in the chamber along the wellbore. Third, by applying Levenberg-Marquardt Algorithm (LMA), the mathematical model is solved The results show that: the oil rate of classic SAGD is significantly improved by the solvent of C5, while the improvement effect of C7 is quite small. As for C3-SAGD, the oil rate is even lower than that of traditional SAGD. This is mainly because C3 decreases the chamber temperature and the solubility of C3 in heavy oil is low, which results in a relatively higher oil viscosity at the chamber edge compared to other solvents. The differentials between the cases, which consider the wellbore or not, is different for different solvent injection. Specifically, oil rate differential for C3-SAGD is the highest and it is twice that for conventional SAGD which has the least differential. C5-SAGD has the second-largest differential which is followed by C7-SAGD. Currently, applying SA-SAGD in a field encounters many challenges, especially in understanding its mechanisms and improving economic efficiencies such as a conflict between the production increase and solvent cost. The newly proposed model not only sheds light on the key mechanism of wellbore/chamber coupling effects, which is usually neglected in the literature but also brings greater benefits by better designing the future SA-SAGD heavy oil recovery projects.
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