The selection of effective surfactants potentially can mobilize oil up to 50% of residuals in mature carbonate oilfields. Surfactants’ screening for such oilfields usually is complicated by the high salinity of water, high lipophilicity of the rock surface, and the heterogeneous structure. A consideration of features of the oilfield properties, as well as separate production zones, can increase the deep insight of surfactants’ influence and increase the effectiveness of surfactant flooding. This article is devoted to the screening of surfactants for two production zones (Bashkirian and Vereian) of the Ivinskoe carbonate oilfield with high water salinity and heterogeneity. The standard core study of both production zones revealed no significant differences in permeability and porosity. On the other hand, an X-ray study of core samples showed differences in their structure and the presence of microporosity in the Bashkirian stage. The effectiveness of four different types of surfactants and surfactant blends were evaluated for both production zones by two different oil displacement mechanisms: spontaneous imbibition and filtration experiments. Results showed the higher effect of surfactants on wettability alteration and imbibition mechanisms for the Bashkirian cores with microporosity and a higher oil displacement factor in the flooding experiments for the Vereian homogeneous cores with lower oil viscosity.

Surfactant flooding can mobilize trapped oil and change the wettability of the rock to be more hydrophilic, which increases the oil recovery factor. However, the selection of surfactants is difficult in the case of high salinity conditions. In this work, we synthesized three novel anionic-nonionic surfactants based on widely used nonionic surfactant nonylphenol polyethoxylated (NPEO) and evaluated their efficiencies for enhanced oil recovery (EOR) in high salinity water (20% NaCl). The modified surfactants showed a decrease in interfacial tension (IFT) up to 10 times compared with the nonionic precursor. All surfactants had changed the wettability of rock to be more hydrophilic according to contact angle measurements. The effectiveness of surfactants was proved by spontaneous imbibition experiments, in which the synthesized surfactants showed a better displacement efficiency and increased oil production by 1.5–2 times. Filtration experiments showed an increase in oil recovery factor by 2–2.5 times in comparison with the nonionic NPEO. These promising results prove that the synthesis of new surfactants by modifying NPEO is successful and indicate that these novel surfactants have a great potential for EOR in high salinity reservoirs.

This article explores the combustion of gaseous fuel in the case of an abrupt change of the specific heat of combustion. Analyzes the changes in the rate of heat when the fuel and air flows are constant. Defines the conditions for which retained the initial rate of heat release and optimal fuel-air ratio.

Summary: This paper highlights the difference between foam injection for gas blocking in production well and injection well and emphasizes the use of polymer enhanced foam. Moreover, this paper shows systematic experimental methods for choosing suitable foam systems for gas blocking in production well considering different factors, which provides a guide regarding what kinds of foaming agents and polymer stabilizers should be used and how to evaluate them for designing a pilot application. The target in this work is the Vostochno-Messoyakhskoye field, operated by Gazpromneft, which is currently experiencing gas channeling from the gas cap in production wells because of strong heterogeneity. Foam has long been considered as a good candidate for gas blocking. However, foam injection for gas blocking in production wells is different from that in injection wells, which requires a long-term impact on gas-saturated highly permeable areas without significantly affecting the phase permeability of oil in the reservoir. Therefore, for gas blocking in production well, a long half-life time of foam is required to sustain stable foam because a continuous shear of surfactant solution/gas cannot be achieved as in injection wells. Thus, reinforced foam by polymer (polymer-foam) is chosen. Four polyacrylamide polymer stabilizers and five anionic surfactants were evaluated using bulk test to determine foaming ability, foam stability, and effect of oil by comparing foam rate and half-life time to determine the suitable foam system with optimal concentrations of reagents. Furthermore, filtration experiments were conducted at reservoir conditions to determine the optimal injection mode by evaluating apparent viscosity, breakthrough pressure gradient, resistance factor, and residual resistance factor. Polymer can significantly improve half-life time (increase foam stability), and the higher the polymer concentration, the longer the half-life time. But simultaneously, a high polymer concentration will increase the initial viscosity of the solution, which not only decreases the foam rate but also increases difficulties in injection. Therefore, an optimal polymer concentration of about 0.15–0.2 wt% is determined considering all these influences. Filtration experiments showed that the apparent viscosity in the core first increased and then decreased with foam quality (the volumetric ratio of gas to total liquid/gas flow). The optimal injection mode is coinjection of surfactant/polymer solution and gas to in-situ generate foam at the optimal foam quality of about 0.65. Filtration experiments on the different permeability cores showed that the gas-blocking ability of polymer-foam is better in high-permeability cores, which is beneficial for blocking high-permeability zone. It should also be noted that under a certain ratio of oil-to-foam solution (about lower than 1 to 1), the presence of high-viscosity crude oil slowly decreased the foam rate with increasing oil volume, but significantly increased the half-life time (i.e., foam stability which is favorable for foam treatment in production well).

High mineralization of water complicates the use of foam in reservoir conditions. Anionic–nonionic surfactants are one of the best candidates for these conditions since they have both high surface activity and salt tolerance. One of the ways to obtain anionic–nonionic surfactants is to modify nonionic surfactants by an anionic group. The type of the group and its chemical structure can strongly affect the properties of the surfactant. In this work, widely-produced nonionic surfactant nonylphenol (12) ethoxylate (NP12EO) was modified by new types of carboxylic groups through the implementation of maleic (NP12EO-MA) and succinic (NP12EO-SA) anhydrides with different saturation levels. The main objectives of this work were to compare synthesized surfactants with nonionic precursor and to reveal the influence of unsaturated bonds in the carboxyl group on the properties of the foam. NaCl concentration up to 20 wt% was used to simulate high mineralization conditions, as well as to assess the effect of unsaturated bonds on foam properties. Synthesized anionic–nonionic surfactants retained surfactant solubility and long-term stability in high-salinity water, but have better foaming ability, as well as higher apparent viscosity, in porous media. The presence of an unsaturated bond in NP12EO-MA surfactant lowers foaming ability at high mineralization.