Foam-Assisted Chemical Flooding at Reservoir Conditions

Abstract

Despite recent drop in the growth of global oil demand, the trend is expected to gradually pick up and continue increasing. Industrial and transportation sectors are still considered the highest consumers of oil. The petrochemicals sector’s demand for oil is increasing sharply and expected to continue in that fashion for the upcoming years. As oil fields age and mature, extraction of oil via primary and secondary techniques becomes, to an extent, inefficient. That encourages more research and development in enhance oil recovery (EOR) methods. In EOR, the aim is to either change a physical or chemical property of reservoir fluid in order to improve the oil recovery factor. The techniques can be categorized as thermal, physical, chemical or gaseous. In this experimental study, the lessons learned from gas flooding methods and surfactant flooding methods are taken into account in order to come up with a novel Foam-Assisted Chemical Flooding (FACF) procedure that aims to enhance the oil recovery factor to its maximum. In this approach, a surfactant slug solution is injected into a core at residual oil after water flooding conditions to mobilize trapped oil by capillary pressure. Then, a surfactant drive solution is co-injected with N2 for foam generation to serve as mobility buffer displacing the accumulated mobilized oil. The experimental study is performed under reservoir conditions of 90 ±1oC temperature and 20 bar of back pressure. In this study, surfactant stability is tested in synthetic formation brine. Then, phase behaviour tests are conducted to identify the capability of the surfactant to reduce o/w interfacial tension (IFT) to ultra-low values. The resulting solutions are categorized into their associated Winsor Types and classified based on salinity as under-optimum, optimum and over-optimum. A final surfactant slug solution is formulated based on these tests. Afterwards, bulk foam tests are performed in absence and presence of crude oil to test surfactant foaming ability and the resulting from stability and strength. Core-flood experiments are carried out to assess the possibility of generating foam in porous media in absence of crude oil and at residual oil to waterflooding. Full EOR FACF experiments are conducted, two at under-optimum and two at optimum salinity conditions. Two FACF experiments are performed with the assistance of medical CT scanner. In one FACF experiment, the foam is pre-generated utilizing a mixing tee and then injected into the Bentheimer sandstone. The study reported here showed that surfactants are not stable in synthetic seawater injection brine, as it tends to form complexes in presence of divalent ions, and subsequently generate precipitations. Stability was achieved by removing the divalent ions from the synthetic brine. In addition, phase behaviour study yielded that surfactant (A) is a better o/w IFT reduction agent than surfactant (B). A distinct layer of micro-emulsion was observed in excess of water and oil phases. On the other hand, surfactant (B) displayed better foaming abilities than surfactant (A) in absence of crude oil. Using surfactant (B), foam was generated in multiple qualities in a Bentheimer sandstone core-flood experiments in absence of crude oil. The critical foam gas fraction was found to be 75%. However, attempts to generate foam in porous media at residual oil to water flooding conditions were not successful. In three FACF core-flooding experiments, weak and unstable foam was generated during the surfactant drive co-injection phase. Whereas, in the last FACF experiment where a mixing tee was utilized, pressure drop and gas breakthrough data show that stable foam was generated. The CT images from two FACF experiments, one at optimum and the other at under-optimum salinity conditions displayed unstable water front in waterflooding phase, and unfavourable mobility conditions, during the surfactant slug injection. However, the effect of salinity conditions was seen in the different oil bank shapes in both experiments. The one at under-optimum salinity condition showed more unstable front. The study reported here showed that the FACF technology yields improving oil recovery of 70±5%, 77±5% and 73±5% for the FACF experiments where it was very challenging to generate foam in-situ and reached up to 80±5% of oil initially in place in the case where foam was pre-generated outside the core (55%, 61%, 59% and 46% are the oil recovery factors after waterflooding, respectively). The study revealed that drive foam strength has a bigger impact than its surfactant slug salinity.