One of the most effective ways to reduce carbon dioxide (CO 2 ) emissions is sequestration in geological reservoirs. CO 2 sequestration in coal formations enhances the methane production from coalbeds (ECBM) in addition to storing CO 2 . CO 2 can be stored in coalbeds in three ways: free gas phase in the pore space or the cleat network system, adsorbed molecules onto the organic surface of the coal, and dissolved in the groundwater within the coal. The performance of this process is dependent on the wettability behavior of the coal−water−CO 2 system. This paper presents an investigation of the effect of the formation water salinity on the wettability behavior of highly volatile bitumen coal. The captive bubble method was used to measure the contact angle in coal−water−CO 2 systems at pressures up to 2000 psi. The contact angle (CA) was measured at different NaCl concentrations (0−20 g/L). The CO 2 adsorption isotherm on the coal surface was examined at different water salinities (0−20 g/L NaCl). Zeta-potential measurements were conducted to understand the effect of salt concentration on coal hydrophobicity. The contact-angle measurements showed that as the pressure increased, the coal wettability inverted from waterwet to gas-wet. The contact angle increased from 61°at atmospheric pressure to 123°at 2000 psi, and the wettability altered from water-wet to CO 2 -wet at pressures around 400 psi. The coal became more CO 2 -wet as the NaCl concentration increased. Furthermore, the adsorption isotherm and the zeta-potential measurements confirmed that the coal became more hydrophobic at high NaCl concentrations. The CO 2 adsorption onto the coal surface increased as the salt concentration increased, whereas the absolute zeta potential value decreased. On the basis of these observations, the injection of CO 2 into highly volatile bitumen coal seams for CO 2 sequestration and ECBM purposes is more efficient as the salt concentration increases.

This study provides a more detailed description of the costotransverse ligaments in human, aimed at investigating some controversial data and disclosing some lacking information concerning the anatomy of such ligaments. Complete spinal segments from the seventh cervical to the first lumbar vertebra were removed from 15 human cadavers (8 males, 7 females) with a mean age of 55 years. The costotransverse ligaments were exposed, bilaterally, at each vertebral level, using a posterior and an anterior approach to the spine. The lateral costotransverse, the superior costotransverse, and the costotransverse ligaments were identified and described. A rudimentary superior costotransverse ligament related to the first rib was also identified. In addition, two thick ligamentous bands were clearly observed in all dissected specimens and were referred to in the study as inferior and posterior costotransverse ligaments. Both bands were subjected to a detailed anatomical study. The importance of such ligaments in maintaining stability of the spine was also discussed.

CO2-enhanced oil recovery (EOR) was started in 1950. Low sweep efficiency and early breakthrough issues were associated with the CO2-EOR system. Foam-EOR was introduced to improve the sweep efficiency instead of polymers to avoid formation damage caused by polymers. Foam stability reduces in high-salinity environments, high-temperature formations (>212°F), and in contact with crude oil. The present study the using of nanoparticles and viscoelastic surfactants (VES) to improve foam mobility control for EOR application. This paper study the CO2-foam stability with using alpha olefin sulfonate (AOS) as a foaming agent and the change on the mobility-reduction factor (MRF) for different foam solutions by adding nanoparticles and VES. To achieve this objective, foam-stability for different solutions was measured at 77 and 150°F using high-pressure view chamber (HPVC). Interfacial tension measurements were conducted to investigate the destabilizing effect of crude oil on the different foam systems. Coreflood experiments were conducted using Buff Berea sandstone cores at 150°F, saturated initially with a dead-crude oil. The CO2 foam was injected with 80% quality as tertiary recovery mode. The oil recovery and the pressure drop across the core were measured for the different foam solutions. Adding silica nanoparticles (0.1 wt%) of size 140 nm and viscoelastic cocamidopropyl betaine surfactant (cocobetaine VES) (0.4 wt%) to the AOS (0.5 wt%) solution improves both foam stability and MRF. In contact with crude oil, unstable oil-in-water emulsion formed inside the foam lamella that decreased foam stability. A weak foam was formed for AOS solution, but the foam stability increased by adding nanoparticles and VES. The interfacial tension measurements revealed positive values for the spreading and the bridging coefficients. Hence, the crude oil spread over the gas-water interface, and lamella films were unstable due to the bridging of oil droplets. The oil recovery from the conventional waterflooding (as a secondary recovery before foam injection) was 48% of the original oil-in-place. From the series coreflood experiments, AOS was not able to enhance the oil recovery. However, more oil was recovered in the presence of nanoparticles (12 %) and VES (18%). Nanoparticles and VES were able to improve the foam stability for AOS solution. Adding nanoparticles is highly recommended for EOR applications, particularly at high temperatures.

CO2-foam has been used as a fracturing fluid to develop unconventional resources and specifically for water-sensitive reservoirs. CO2-foam not only reduces formation damage by minimizing the quantity of aqueous fluid which enters the formation, but also reduces the water consumption for environmental conservation purposes. CO2-foam as a hydraulic fracturing fluid provides for rapid cleanup during flowback. Although it is common to use surfactants to generate and stabilize foams, they tend to degrade at high temperatures (>212°F) and in high-salinity environments. The present work evaluates new foaming solutions that incorporate nanoparticles to investigate the mobility-control performance when such foams are used as hydraulic fracturing fluids. Of special interest in this work is the study of mobility reduction factor (MRF) of CO2 foam, generated with polymer-based solution, e.g., guar gum, in the presence and absence of nanoparticles, to assess the apparent fluid viscosity at high temperature and high salinity. To achieve this objective, coreflood tests were conducted on different Buff Berea sandstone cores at both 77 and 250°F. CO2 gas was injected with the different solutions simultaneously to generate foam with 80% quality. The pressure drop across the core was then measured to estimate the MRF. Results show that alpha olefin sulfonate (AOS) improves the MRF by 300% compared to NaCl solution. Adding silica nanoparticles and guar-gum to the AOS solution improves both foam stability and MRF. At 250°F, the AOS solution retained foam stability, while the MRF increased to 28 compared to that of at 77°F. Choice of surfactant concentration is a critical parameter in generating stable foam. However, the economical use of surfactants is limited by various factors such as surface adsorption, process cost, surfactant loss, and surfactant degradation at high-temperature reservoirs. Nanoparticle solutions can be employed to improve CO2 foam stability as well as MRF factor. Adding nanoparticles is highly recommended for hydraulic fracturing applications, particularly in fracturing stimulation at high-temperatures.