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 CO2 and surfactant as a CO2-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 CO2/alpha olefin sulfonate (AOS) solution as a new foaming solution is introduced for optimizing surfactant concentration in order to generate a stable CO2-foam in unconventional reservoirs. Several experimental studies were conducted to obtain the optimal surfactant concentration using a pendant drop method for CO2/solution and CO2/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 N2. 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 CO2-foam in unconventional reservoirs.
Miscibility with oil lies among the main advantages of dense CO2 injection for pore scale oil displacement during tertiary recovery. At reservoir scale, injecting dense CO2 in the form of foam can also improve its sweep efficiency. However, although the use of such miscible dense CO2 foams has been considered in over twenty pilots since the 1980’s, only few lab studies have considered foams formed with CO2 in this particular thermodynamical state. Indeed, dense CO2 has solvation properties and a viscosity higher than that of a gas. Although the generic term of foam is used, dense CO2 actually has liquid-like properties, and dense CO2 foams should be coined emulsions. This impacts several attributes of these dispersions in porous media, such as Mobility Reduction Factors (MRF) and behavior in presence of oil.
We present new results demonstrating that classical foamers are not effective in improving mobility control of dense CO2 in porous media. However, relatively high MRF can be achieved using carefully formulated surfactants. Based on these findings, we study the impact of foam on miscible flooding efficiency in coreflood experiments. Reversely, we also evaluate how miscibility of CO2 with oil impacts foam MRF. Our approach is based on multiple corefloods experiments, with different formulations, at various oil saturations. Additionally, physical-chemistry measurements such as interfacial tension estimations and foam stability monitoring are performed in reservoir conditions (pressure and temperature). This set of experiments shows that besides ability to reduce dense CO2 mobility in porous media, a balance must be found between maximizing MRF and minimizing the risk of emulsion formation in porous media.
This paper brings new insights on the interpretation of CO2 foams coreflood results, based on the thermodynamical properties (solvation power, density, viscosity) of the CO2 phase. In particular, it provides the reader with a clearer view of gas properties that must be considered when analyzing results of dense CO2 foams corefloods. This can help reconcile seemingly contradictory results appearing in the literature, particularly regarding the values of MRF obtained with CO2 foams as a function of pressure and in the presence of oil.
Injection of dense supercritical CO2 (sc-CO2) represents today more than half of the EOR projects carried out in USA. While sc-CO2 flooding is very effective in mobilizing trapped oil at the microscopic (pore-scale) level, this technology is usually limited by unfavorable mobility ratio and gravity segregation issues. In that context, use of dense CO2 foams (emulsions) may be one of the most robust methods for improving sc-CO2 flooding efficiency and maximizing oil recovery at
reservoir scale. However, surfactant screening for dense CO2 foams has until now been extremely time consuming and limited to a few products due to strong technical constraints (high pressure equipments). Here, we report an original set of high throughput screening for optimizing dense CO2 foams formulations. The formulation yielding the best results is further characterized in corefloods experiments.
We use a proprietary high pressure jet-drop transition technique to screen interfacial properties of molecules at the dense CO2 / brine interface. The surfactants showing significant interfacial activities between aqueous solution and sc-CO2 are selected for the next steps. We use an autoclave to generate highly sheared foam with low cell sizes and study generated foam stability in a high pressure variable volume view cell. Structure/properties relationships are extracted from our numerous screening experiments and complement existing design rules for dense CO2 foam formulations.
A surfactant formulation yielding superior sc-CO2 foam stability is tested for mobility reduction in low-permeability carbonate cores. Using a CO2/aqueous solution co-injection scheme, we observe various flow regimes for different fractional flows. We confront these first results to the existing theories of foam flooding in porous media.