|dc.description.abstract||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 widely used to generate stable foam in high-temperature and high-salinity environments such foam can degrade in these harsh conditions.
Oil production using enhanced oil recovery techniques and especially through performing hydraulic fracturing has been increased in recent years. This in turn significantly escalates the demand for high performance fracturing fluids which cause low formation damage in porous medium. Traditional fracturing fluids use water viscosifying agents such as guar gum and its derivatives to support and carry the proppant. However, guar gum forms an insoluble residue in the formation, and these insoluble materials plug pore throats, causing formation damage that could be fatal to the reservoirs.
The purpose of this dissertation is to develop nanoparticle-stabilized CO2 foam by adding nanoparticles such as SiO2 and Fe2O3 in combination with guar-gum polymer, and viscoelastic surfactant (VES) to surfactant solutions stabilize CO2-foam to enhance its stability. Additional objectives include measuring contact angle and surface tension of nanoparticle solutions, and measuring the zeta potential of nanoparticle solutions to better understand the parameters that affect CO2-foam stability. Moreover, in this work, mobility reduction factor (MRF) of CO2-foam was investigated for 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.
Experimental results of this work indicated that the critical micelle concentration (CMC) value increases as temperature increases. The CMC value 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. Temperature and pressure had a negative effect on the foam stability when surfactant was used. However, adding nanoparticles and/or polymers could overcome this drawback and improve the foam stability. Polymer-surfactant-based solutions such as guar-gum/AOS generate foams with significantly shorter half-life time than that of the surfactant-nanoparticle dispersion like AOS-SiO2. That is, under same conditions, polymer-surfactant based foams are less stable compared to surfactant-nanoparticle based foams. Coreflood results also show that AOS improves MRF by 300% compared to that of brine solution. Adding SiO2 nanoparticles and guar-gum to the AOS solution improves foam stability and MRF simultaneously.
Choice of surfactant concentration is a critical parameter in generating stable foams. 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.||en