Summary Foamed fluids have been used for decades to diminish formation damage in nearly all kinds of reservoirs over a wide range of pressures and temperatures. Although water-based fluids are widely used in the oil industry as one of the most-economic hydraulic-fracturing methods, foam is another viable alternative to fracture water-sensitive reservoirs where damage to pore throats is caused by swelling clays or fines migration. CO2 foam not only reduces formation damage by minimizing the quantity of aqueous fluid that enters the formation, but also significantly improves sweep efficiency. Even though surfactant is commonly used to generate stable foam in high-temperature and high-salinity environments, such foam can degrade in these harsh conditions. The main objective of this study is to improve the stability of CO2 foam by the use of a mixture of CO2/alpha olefin sulfonate (AOS) solution with nanoparticles, guar gum, or viscoelastic surfactants (VESs). Foam stability is studied for various solutions by the use of a high-pressure view-chamber (HPVC) setup to find the optimal surfactant and nanoparticle concentration at which higher foam stability in the CO2 foam system can be reached. In addition to surfactant and nanoparticle concentration, the effects of temperature, pressure, and salinity on foam stability were studied. Temperature ranged from 75 to 212°F, and pressure increased from atmospheric to 800 psi. AOS solutions were prepared with brine and surfactant concentrations ranging from 1.0 to 10 wt% of NaCl and zero to 1 wt% of AOS. Temperature and pressure had a negative effect on the foam stability when AOS solutions were used. However, nanoparticles improved the foam stability for AOS, AOS and guar gum, and AOS with VES solutions.
Foamed fluids have been used for decades to diminish formation damage in nearly all kinds of unconventional reservoirs with a wide range of pressures. Although water-based fluids are widely used in the oil industry as one of the most economic hydraulic fracturing methods, foams are another substitute to fracture water-sensitive reservoirs at which damage to pore throats is caused by swelling clays or fines migration. The mixture of CO 2 and surfactant as a CO 2 -foam not only reduces formation damage by minimizing the quantity of aqueous fluid which enters the formation, but significantly improves sweep efficiency. Even though it is common to utilize surfactants in order to generate and stabilize foams, surfactants tend to degrade at high temperatures and in high salinity environments. Adding nanoparticles can solve the aforesaid problems and can increase foam stability.The choice of surfactant concentration is a critical step in preparing more stable foams. In the present work, using CO 2 /alpha olefin sulfonate (AOS) solution as a new foaming solution is introduced for optimizing surfactant concentration in order to generate a stable CO 2 -foam in unconventional reservoirs. Several experimental studies were conducted to obtain the optimal surfactant concentration using a pendant drop method for CO 2 /solution and CO 2 /nano solution. Moreover, the effects of temperature, pressure, salinity, and surfactant concentration on surface tension and the critical micelle concentration (CMC) value were studied at high pressure and high temperature (HP/HT). In these experiments the temperature ranged from ambient conditions to 302°F, while the pressure increased from atmospheric up to 435 psi. AOS solutions were prepared using different brine concentrations ranging from 1 to 10 wt% of NaCl and different surfactant concentrations from 0 to 1 wt%.Experimental results indicated that the CMC value increases as temperature increased. It also decreased while salt concentration increased. Furthermore, for a given temperature and salinity, the results did not exhibit changes in the CMC value when the pressure increased. The addition of nanoparticles decreases the CMC value.A number of research studies have been conducted to investigate the CMC value and surface tension for AOS at ambient conditions using N 2 . However, minimal work has been performed in order to determine such characteristics at reservoir conditions. The present work will provide a new foaming solution in order to evaluate and optimize surfactant concentrations. The present work will also investigate the effect of mixtures of surfactant and nanoparticles on the formation of stable CO 2 -foam in unconventional reservoirs.
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.
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