In 1949, Toms (Toms B.A., (1949, 1977)) observed that small amounts of a drag reducing agent (DRA) could cause a considerable drag reduction in turbulent pipe flow. In application of polymer enhanced oil recovery, degradation of polymers in the supply lead could cause clogging. It was, however observed that surfactants at sufficiently high concentration also showed drag reduction without the problem clogging. A DRA reduces the energy loss by friction and unstable flow, thus improving injection throughput with the same pressure pump and thereby reducing the exergetic pumping costs. This study investigates experimentally the drag reducing capacity of surfactants and compares it to the drag reducing capacity of polymers. For the experiment, a set-up consisting of a pump, a coiled test tube with a length of 1.48 m and an inner diameter of 0.5 mm and pressure gauges is built. The diameter of the coil is 12.5 cm. We use a pump capable of injection up to 200 ml/min. The pressure drop is measured between the entrance and end of the tube. The injection rate is varied between 1 and 200 ml/min, roughly corresponding to Reynolds numbers between 50 and 10,000. The additives are dissolved in brine with a 33,000 ppm salt concentration. The viscosity of the solution is dependent on the concentration of the DRA. The ratio of the measured pressure drop with only brine and the pressure drop with the DRA solution was used to calculate the drag reduction (DR) factor, as from a technical point of view we are only interested whether adding DRA reduces the drag with respect to the original brine solution. From an academic point of view, we remark that for low concentrations the viscosity enhancement due to the presence of the DRA is negligible. As polymers we use xanthan (a biopolymer), and a synthetic emulsion polymer based on polyacrylamide. Maximum DR factors are 23% for xanthan at 90ppm and 32% at 90ppm for the synthetic emulsion polymer. DR only occurs at turbulent conditions. Three types of surfactants, each from a different branch of surfactants are used in this study. The surfactants used are AOS {훼-Olefin Sulfonate}, CTAB {hexadeCylTrimethylAmmonium Bromide} and APG {Alkyl PolyGlucoside} which are a cationic, anionic and a nonionic surfactant respectively. The surfactants did not show any DR at (for DRA applications) high concentrations up to 20.000ppm. Addition of Sodium Salicylate (NaSaL) to CTAB with a 1:1 ratio led to a maximum DR of 33% at 2500 ppm concentration. Several pressure gauges have been installed along the test tube in order to observe how the pressure drops along the tube, how the DRAs affect these pressure drops and at what location of the test tube the DR factor is the highest. It is found that xanthan has the same DR factor at each location of the test tube, the emulsion polymer has a decreasing DR factor as the distance from the inlet of the test tube increases and the CTAB+NaSaL DRA has an increasing DR factor as the distance from the inlet increases. The DRAs are sheared using a constriction in the flow loop while the degradation is monitored. It is observed that xanthan is less susceptible to degradation in comparison to the emulsion polymer due to its more rigid chemical structure. But xanthan and the emulsion polymer would be inefficient to use in looped flow systems as they are affected by degradation. The CTAB+NaSaL DRA on the other hand shows no degradation meaning that the micellar rod-like structures that give the DR effect are being repaired when the shear force is being removed. However, for surfactants higher concentrations (1000-2500 ppm) are required.

As the world population is projected to keep growing over the next decades, an increase in energy is required and hydrocarbon fuels will remain as the primary source of energy. Since most of the hydrocarbon resources have been discovered, it is necessary to extend the use of Enhanced Oil Recovery (EOR) methods on these mature fields to increase the fraction of oil recovered. Foam-EOR has shown to improve sweep efficiency during gas injection. However, there are two challenges regarding the use of foams: 1) the performance of the surfactants needed to generate foam and 2) the cost of these surfactants. In this study the performance of six surfactants was tested for steam foam applications; focusing on solubility, thermal stability, foam stability and adsorption in porous media. The solubility of the surfactants ranged from good to poor. However, poor solubility can be enhanced by heating up the solution. The surfactants tested showed a large range of stability behavior, from very good to very poor. The surfactant with the best thermal stability at 275°C has a molecule with three characteristics related to high thermal stability: 1) Sulfonate head, 2) aromatic compound attached to the head, and 3) a long hydrophobic tail (above 18 carbon atoms). The other surfactants, with a low to very low thermal stability lacked one or more of these characteristics. The surfactant with the best thermal stability also had the best foam behavior in porous media at 180°C, showing a max. apparent viscosity of 0.42 Pa·s and a Mobility Reduction Factor of 2818. Finally, for this surfactant, the dynamic adsorption in Bentheimer sandstone was 0.059 mg/grock at 120°C. Additionally, an exergy analysis was carried out to assess the cost of the surfactant from a thermodynamic point of view. For this purpose, the Exergy Recovery Factor was calculated for a system on which the Water Alternating Gas (WAG) and Surfactant Alternating Gas (SAG) EOR methods are applied, with different gases injected. The system includes from the initial capture of the gas and transport of the gas to the final oil and gas production from the reservoir and separation and recirculation of produced fluids. Despite the high exergy cost of the surfactant, the exergy recovery factor was higher for SAG than for WAG, meaning that more energy is extracted than invested. It was also found that less CO2 was produced per barrel of incremental oil extracted with SAG than with WAG.