Foamed fluids with carbon dioxide in the gas phase have been recently studied as fracturing fluids to develop unconventional resources. This type of fracturing fluid is superior to water- or oil-based fracturing fluids for unconventional reservoirs, which are prone to damage by clay swelling and blocking of pore throats in water- or oil-rich environments. Conventional CO2 foams with surfactants have low durability under high temperature and high pressure, which limit their application. Nanoparticles provide a new technique to stabilize CO2 foams under harsh reservoir conditions. As CO2 foams will be applied as carrier fluids for proppant transport, it is essential to determine the in situ rheology of CO2 foams stabilized by nanoparticles under reservoir conditions in order to predict proppant transport and effective microchannels in reservoir fractures for improving oil production. This work studied the in situ shear viscosity and foam stability of supercritical CO2 foams stabilized by nanosilica (SiO2) in the flow loop apparatus with shear rates of 5950–17850 s–1 at a pressure of 1140 ± 20 psig and a temperature of 40 °C. Supercritical CO2 with density of 0.2–0.4 g/mL and viscosity of 0.02–0.04 cP under typical reservoir conditions was applied to generate foams. The foams were tested with high foam qualities up to 80% to minimize the usage of water. The effects of shear rates, surfactant, foam quality, salinity, and nanoparticle size on the rheology of gas foams were experimentally investigated. The foam texture and stability were observed through an in-line sapphire tube after generation under reservoir conditions. Finely textured and stable foams with high foam quality were generated. CO2 foams generated by different systems and gas qualities showed complex rheology and stability. The rheology of the foams demonstrated both shear-thinning and shear-thickening behaviors. The salinity significantly affects the foam behaviors by greatly decreasing foam stability, resulting in foam rheology in two ways depending on components, foam quality, and shear rates. While the viscosities and interfacial affinity of CO2 foams stabilized by nanoparticles under atmospheric pressure have been widely studied recently, no work has been reported to study the dynamic rheological behaviors of CO2 foams stabilized by nanoparticles and their stability/morphology after shearing under high pressure and elevated temperature. This research provides a pioneering insight into the rheology of viscous supercritical CO2 foams stabilized by nanoparticles.
Foamed fluids with the gas phase of carbon dioxide (CO 2 ) have been applied as fracturing fluids to develop unconventional resources. This type of fracturing fluids meets the waterless requirements by unconventional reservoirs, which are prone to damage by clay swelling and blocking pore throat in water environment. Conventional CO 2 foams with surfactants have low durability under high temperature and high salinity, which limit their application. Nanoparticles provide a new technique to stabilize CO 2 foams under harsh reservoir conditions. It's essential to determine in-situ rheology of CO 2 foams stabilized by nanoparticles in order to predict proppant transport in reservoir fractures and improve oil production.The shear viscosity and foam texture of non-Newtonian fluids under reservoir conditions are critical to transport proppant and generate effective micro-channels. This study determined the in-situ shear viscosity of supercritical CO 2 foams stabilized by nano-SiO2 in the Flow Loop apparatus with shear rates of 5950~17850 s Ϫ1 at the pressure of 1140Ϯ20 psig and the temperature of 40°C. Supercritical CO 2 with the density of 0.2~0.4 g/ml and the viscosity of 0.02~0.04 cp under typical reservoir conditions were applied to generate foams. The foams were tested with high foam quality up to 80% to minimize the usage of water. The effects of shear rates, salinity, surfactant, and nanoparticle sizes and on the rheology of gas foams with different foam qualities were experimentally investigated. The foam texture and stability were observed through an in-line sapphire tube. Further, proppant transport by CO 2 foams and the placement in fractures were analyzed by considering the rheology of non-Newtonian fluids and the mechanisms of gravity driven settling and hindered settling/slurry flow.The conditions of nanoparticle foaming systems were optimized through orthogonal experimental design. The dense and stable foams were generated and observed under high pressure and elevated temperature conditions. It was observed that CO 2 foams with high quality of 80% demonstrated the highest viscosity and stability under optimal conditions. The foams with nanoparticles demonstrated both shear-thinning and shear-thickening behaviors depending on foam quality and components. The salinity and nanoparticle size affect foam rheology in two ways depending on components, foam quality, and shear rates.While the viscosities of CO 2 foam stabilized by nanoparticles have been widely studied recently, no work has been done to observe the stability and texture of supercritical CO 2 foam after shearing under high pressure and high temperature, not to mention proppant transport by CO 2 foam. This study provided a pioneering insight to the proppant transport by viscous supercritical CO 2 foam stabilized by nanoparticles.
The SACROC Unit in the Permian Basin has been under carbon dioxide (CO 2 ) injection for enhanced oil recovery (EOR) for almost forty years since CO 2 injection commenced in 1972. The mature CO 2 operations in the SACROC Unit make it an optimal site for studying CO 2 sequestration in conjunction with EOR. A pilot demonstration project was performed in a fivespot pattern, beginning at the end of 2008. The objective of this study is to understand the capacity and flow patterns of the CO 2 plume to determine sequestration potential in conventional oil reservoirs.The pilot site locates in the Northern SACROC platform and was set up as a five-spot pattern consisting of 4 injectors and 1 center producer. Water and CO 2 injection had occurred earlier in the SACROC Unit during reservoir development. The pilot testing started in 2008 and has been under CO 2 injection since then. After thirteen months of CO 2 injection, the production data from the pilot showed that the oil production rate of the producer (well 56-17) increased over tenfold during the first year of CO 2 injection which demonstrated significant enhanced oil recovery by CO 2 injection. This paper describes how the injection process in the SACROC pilot was simulated using a compositional simulator, Computer Modeling Group's GEM. A simulation model with 47,104 grids was developed with geophysical data characterized from 3D seismic surveys and well logs. The simulation area is 6640 ft * 6640 ft * 840 ft, consisting of five wells in the pilot site. History matching gas, oil, and water production for each well since first drilled was performed to verify the model. The EOR under three injection schemes was predicted. The CO 2 storage capacity under residual and solubility trapping mechanisms during CO 2 miscible displacement was simulated and analyzed. This study demonstrated CO 2 sequestration in oil reservoirs to be a low-risk, promising method for mitigating CO 2 discharge into the atmosphere. Relative permeabilityPreviously reported laboratory results (Brummett, 1976) verified residual oil saturation by water displacement of 26.1%. Experimental work performed by the Anderson et al. (Anderson et al., 1954) established an average irreducible water saturation of 17.7%. These values were used as the endpoints of the water-oil relative permeability relationship. The water/oil relative permeability curves used in this work are shown in Figure 7. Simulation results discussionThe reservoir performance under stimulation and CO 2 migration status was simulated by a compositional simulator, CMG's GEM. The fluid properties were tuned by PVTsim and CMG's Winprop. History matchThe history match was accomplished with two main constraints: one specifies oil rate SC (surface rate) production and matches the gas production and water production, the other specifies gas rate SC (surface rate) and matches the oil production Several simulations have been performed for the SACROC northern platform. Early simulation used an artificial model or and water production.
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