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.

Oil is one of the major contributors to energy consumption. Oil reserves are expressed as the total amount of economically and technically producible oil. Total oil consumption is increasing (per capita it remains more or less the same) but it has no unambiguous influence on the remaining reserves due to new discoveries. However, increasingly sophisticated recovery methods are used to produce oil i.e. enhanced oil recovery methods. A recently proposed enhanced oil recovery method is by injection of low-salinity water in completely oil-wet reservoirs, which leads to more water-wet behavior and “consequently” to improved oil recovery.
This report will focus on the effect of wettability on the recovery efficiency. Based on the papers by Lomeland, Ebeltoft and Thomas we derive so-called LET relative permeability curves that only depend on irreducible water saturation. This is possible by using the irreducible water saturation dependence of the residual oil saturation, end point relative water permeability and the sketched behavior (Lomeland, Ebeltoft and Thomas) of the other six parameters. Admittedly this is a gross simplification, but it grasps the essence of the relative permeability behavior and makes it possible to study the recovery in terms of two parameters viz. the irreducible water saturation and viscosity ratio as opposed to eight relative permeability parameters and the viscosity ratio. High irreducible water saturation is both indicative of pore size heterogeneity and water-wet behavior. We use the theory of Buckley-Leverett to construct recovery curves for 1D and 2D displacement and various mobility (M = displacing fluid mobility / displaced fluid mobility) ratios. We solve the 1-D equations both analytically (using fractional flow theory) and numerically. For the numerical simulations in 1D and 2D we use COMSOL 5.2©. The simulations show that water-wet behavior is conducive to stable displacement, however, low recovery at breakthrough, whereas intermediate oil-wet behavior is more unstable but conducive to high ultimate recoveries. Completely oil-wet behavior leads to less stable displacement and low ultimate recoveries.