Surfactant flooding as a potential enhanced oil recovery technology in depleted reservoirs after water flooding has attracted extensive attention. In this study, 12 surfactants belonging to five different types of surfactants and their compounded formulations were investigated for surfactant flooding under 90−120 °C and 20 × 10 4 mg/L salinity. Two surfactant formulations obtained a stable ultralow interfacial tension (IFT) level (≤10 −3 mN/m) with crude oil after aging for 125 days. The surfactant formulations were used to further investigate the effects of the initial IFT values, the dynamic reduction rate of IFT, and the surfactant concentration and emulsification on oil recovery through core flooding experiments. The results indicated that oil recovery increased with the decrease of the initial IFT values and the increase of the dynamic reduction rate of IFT. The 10 −3 mN/m IFT level yielded an additional oil recovery of approximately 7% compared with the 10 −1 mN/m IFT level. However, under the same IFT level (10 −4 mN/m), it was not the bigger the surfactant concentration that resulted in a higher additional oil recovery. In four surfactant concentrations (0.2%, 0.5%, 1%, and 3%), the 0.5% surfactant formulation obtained the highest oil recovery of 36.65%. Further study manifested that emulsification has important effects on oil recovery. When surfactant concentrations were increased to 1% and 3%, the emulsification was too strong, which makes it more difficult to displace oil. The two selected surfactant formulations could successfully yield additional oil recovery of 20−26%, which indicates these two formulations have great potential for improving oil recovery in high temperature and high salinity oil reservoirs.

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Foam performance during oil displacement is closely related to the reservoir environment. In this study, both bulk and porous media experiments were conducted to investigate surfactant foam and polymersurfactant foam behaviors at high temperature and with crude oil. After aging at 90 C for 90 days, the foam drainage half-life of the aged polymer-surfactant foam was four times longer than that of the fresh surfactant foam. Scanning electron microscope images indicated that, even experienced high temperature aging, the polymer and surfactant could still develop multilayer complexes to enhance the foam film strength. Within a certain oil content, the foam stability in the presence of oil could be better than in the absence of oil. Stereoscopic microscope images revealed that the existing form and content of oil in the foam film had played a vital role. Core flooding experiments further confirmed that stable surfactant foam and polymer-surfactant foam could generate in the presence of waterflooded residual oil and give rise to additional oil recovery of 15.35% and 35.75% at 90 C, respectively. The positive responses of this study may be attractive to potential foam field applications.

Summary The paper adopts the view that the liquid droplets entrained in gas wells tend to be flat and deduces new formulas for the continuous removal of liquids from gas wells. The results calculated from the formulas are smaller than those of Turner et al. However, the predicted results are in accord with the practical production performance of China's gas wells with liquids. The paper also gives the simple forms of these formulas and shows the load-up and near load-up production performance as well as unloaded gas wells through the wellhead, producing performance figures. Introduction Gas produced from a reservoir will, in many cases, have liquidphase material with it, which can accumulate in the wellbore over time when transporting energy is low enough in a low-pressure reservoir. The liquids accumulated in the wellbore will cause additional hydrostatic pressure on the reservoir, resulting in a continued reduction of available transportation energy and affecting the production capacity. In some cases, it even causes gas wells to die. It is essential to investigate the cause for gas-well load-up and to determine the minimum gas flow velocity and rate to transport liquids to surface. Turner et al.1 compared two models - the continuous-film and the entrained-drop-movement models. He proved that the entrained- drop-movement model was more adequate for explaining gas-well load-up and used it to further investigate this. Assuming the liquid droplets were spherical, Turner et al.1 deduced the formulas used to calculate the minimum gas-flow velocity and rate to remove liquid droplets with +20% adjustment. The minimum gasflow velocity and rate are known as the terminal velocity and the critical rate. Turner et al.1 also suggested that, in most instances, wellhead conditions controlled the onset of liquid load-up and the gas/liquid ratio in the range of 1370 to 178 571 m3 /m3 and did not influence the terminal velocity and critical rate. There are many gas wells producing at rates less than the minimum flow rate formula, and these wells are still in a good production state in China. To obtain a relatively accurate critical producing rate, the engineers in China's gas fields adjusted the critical rate, reducing by two-thirds. Steve2 found that the unadjusted liquid-droplet model tended to offer a better match to the field data. The model still cannot obtain a suitable critical rate to explain the phenomenon of some gas wells that should be loaded up with his model but are not. This paper presents formulas for predicting the terminal velocity and critical rate after analyzing the shape of a liquid drop entrained in a high-velocity gas stream. With the present model, the calculated results are in conformity with the practical daily production record of gas wells. For easier application, this paper puts forward simple forms of the deduced formulas, analyzing different factors that affect the removal of liquids from gas wells. Steve3 analyzed the wellbore behavior of load-up, near load-up, and unloaded gas wells. This paper shows the production performance of these with wellhead production-rate figures through which engineers can have a better understanding of their effect on a gas well's production performance. Terminal-Velocity and Critical-Rate Theory Shape of Entrained Drop Movement. Hinze4 showed that liquid drops moving relative to a gas are subjected to forces that try to shatter the drops, while the surface tension of the liquid acts to hold the drop together. He determined that it was the antagonism of two pressures - velocity and surface tension. The ratio of these two pressures is the Weber number, NWe = v2 ?gd/s. If the Weber number exceeded a critical value, the liquid drop would be shattered. For free-falling drops, the value of the critical Weber number was on the order of 20 to 30. Turner et al.1 deduced the terminal-velocity and critical production-rate formulas with the larger Weber number value (30). These formulas were put forward without taking the deformation of liquid droplets into consideration. As a liquid drop is entrained in a high-velocity gas stream, a pressure difference exists between the fore and aft portions of the drop. The drop is deformed under the applied force, and its shape changes from spherical to that of a convex bean (called a flat shape here) with unequal sides (Fig. 1). Spherical liquid drops have a smaller efficient area (held by gas) and need a higher terminal velocity and critical rate to lift them to the surface. However, the flat ones have a more efficient area and are easier to be carried to the wellhead. As mentioned previously, the critical rate determined from Turner et al.1 is by far higher than that of the field data in China. This also suggests that entrained liquid droplets can be flat. Formulas. A rigorous determination of the terminal velocity of a deformed liquid drop presents many difficulties. Nevertheless, the velocity can be estimated under the hypothesis that the drop tends to be flat, as shown in Fig. 2. When the liquid drop remains motionless relative to the wellbore (i.e., the velocity of the liquid drop relative to gas is v and equals gas velocity vg), it is clear that vg is the terminal velocity vt. With the condition that the gravity of a liquid drop equals the buoyancy plus the drag force (see Fig. 2), we haveEquation 1 When the liquid drop changes from a spherical shape to a flat one, its projected area differs. The area s is determined in the Appendix. Substituting Eq. A-9 into Eq. 1, we get the falling velocity v of the drop relative to a high-velocity gas. Because the velocity equals the terminal velocity on the balance condition, we now have the following form.Equation 2