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The demand for freshwater keeps increasing on a global scale, and on the other hand, the availability of freshwater keeps diminishing. Groundwater has been identified as the largest source of freshwater that is readily accessible. Although the water is available for abstraction, it must be treated to meet application standards. Membrane processes are the options that industry and researchers are turning to for the purification of groundwater. This review provides an insight into the use of pressure-driven membrane processes for groundwater treatment, with focus on the spiral wound membrane module. A brief description of what a spiral wound module is and the plant set-up in which it is used is given. The various applications of the spiral wound module with regards to groundwater treatment have been reviewed. The shortcomings and challenges limiting the application of spiral wound modules and by extension, the treatment plant itself have been highlighted. To cap it all, the opportunities that can be exploited to overcome these challenges and position pressure-driven membrane processes for groundwater treatment as the go-to purification method have been discussed. [ABSTRACT FROM AUTHOR]

Well injectivity and storage capacity defines the storage potential of a CO2 capture, utilization, and storage (CCUS) facility. Formation temperature has high impact on the phase behavior and flow properties of CO2 such as density and viscosity. The effect of temperature on CO2 injectivity, especially in the wellbore injection inlet, is not well understood. We investigated the thermal behavior of CO2 from the wellhead to the reservoir using simple theoretical models that capture the major heat transfer mechanisms. The effect of CO2 injection flow rate and injection time on the temperature of CO2 were studied. We found that for the same initial CO2 injection temperature and formation intake temperature, the injected CO2 in the well is cooler than the surrounding formation from the wellhead to the bottomhole. The temperature difference increased with increasing injection flow rate and injection time. The results show that although CO2 may attain supercritical state at bottomhole, the temperature difference between CO2 in the wellbore and the reservoir could be significant. The results also suggest that CO2 could attain thermal equilibrium with the reservoir at a flow distance of about 600 ft into the formation depending on the injection flow rate and reservoir temperature. The thermal disequilibrium of CO2 in the wellbore vicinity where fluxes are also high could affect CO2 injectivity and the mobility of CO2 during CCUS and enhanced oil recovery (EOR) operations. The present findings provide vital understanding of the effect of thermal instability on CO2 injectivity especially in the wellbore injection inlet. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Deep saline reservoirs have the capacity to hold large volumes of CO 2 . However, apart from the high brine salinity, which poses an injectivity challenge, a high percentage of saline reservoirs are also fractured. The mechanisms of drying and salt precipitation and the resulting impact on CO 2 injection are unique in fractured reservoirs. Analytical models were developed to investigate the impact of salt precipitation on CO 2 injectivity and storage capacity. Two types of fractured saline reservoirs were considered: type I fractured reservoirs, where storage capacity and injectivity are contributed by only fractures, and type II fractured reservoirs, where both fractures and the adjacent rock matrix blocks contribute to CO 2 storage and injectivity. We found that, depending on the initial brine salinity, salt precipitation could severely impair CO 2 injectivity and reduce storage capacity. Salt precipitation had a fourfold impact on CO 2 injectivity compared to storage capacity. Type I reservoirs with high irreducible brine saturation were less susceptible to salt clogging in the fractures. The results also suggest that fractures with rectangular aperture were less likely to be plugged by salt compared to elliptical fractures. Contrary to previous reports, some fractured deep saline reservoirs may not be suitable for CO 2 storage. Generally, type II fractured reservoirs were found to be more suitable for CO 2 storage in terms of susceptibility to salt clogging. The findings provide valuable understanding of the mechanisms and effect of drying and salt precipitation on CO 2 storage potential, making a strong case for CO 2 storage in naturally fractured deep saline reservoirs., Competing Interests: The authors declare no competing financial interest., (Copyright © 2020 American Chemical Society.)