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).

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.

Gas breakthrough is becoming an increasingly common problem, with a growing number of gas-and-oil fields being developed. Gas-and-oil fields are usually characterized by a complex geological structure, high reservoir heterogeneity, low net-pay thickness, and large gas cap, which lead to gas breakthrough, especially in horizontal production wells. Chemical gas-blocking methods lately have gained more scientific interest and are becoming more applicable in the fields, the reason being the potential for adjusting the type and properties of chemical gas-blocking agents (GBA) to increase blocking selectivity. It is hard to numerically simulate the gas-blocking properties of GBA due to the complexity of their structure and behavior. Flooding experiments of GBA injection and blocking ability in zones with different permeabilities and saturations can provide reliable data to choose the right GBA. However, there are no studies with an experimental comparison of the several GBA with a variation of reservoir core permeability and saturation. In this work, blocking ability and selectivity of three hydrolyzed polyacrylamide-based GBA in the coreflooding experiments were compared: polymer-foam, foam-gel, and gel. East-Messoyakhskoye gas-and-oil field fluid and core material were used. This field faced a gas breakthrough in middle-stage development through high-permeability zones into long horizontal production wells. Coreflooding experiments were carried out in two stages (injection and breakthrough of GBA) with the simulation of four common reservoir zones: oil-saturated low permeability, gas-saturated high permeability, oil-saturated high permeability, and gas-saturated low permeability. Results show that polymer-foam achieved low injection and medium blocking selectivity. The gel showed higher damaging risks due to the lowest selectivity in both the injection and breakthrough stages. The best blocking selectivity and blocking efficiency were achieved by foam-gel due to low initial viscosity and the in situ generation of a rigid gas-blocking structure.

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.

Messoyakhskoye field, operated by Gazprom Neft, is currently experiencing gas channeling from gas cap in production wells because of strong heterogeneity. Foam for a long has been considered as a good candidate for gas blocking, (Svorstol I. et al., 1996), (Hanssen, J. E., & Dalland, M. 1994), (Aarra, M. G. et al., 1996). However, foam injection for gas blocking in injection well is different from that in production well, where it is necessary to selectively and long-term impact on gas-saturated highly permeable areas without affecting the phase permeability of oil in the reservoir. This paper provides detailed laboratory studies that show how to determine suitable foam systems for gas blocking in production well. For gas blocking in production well, a long half-life time is required to sustain stable foam because a continuous shear of surfactant solution/gas can't be achieved like in injection well. Therefore, reinforced foam by polymer is chosen. Four polymer stabilizers and five foam agents 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. 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 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 core first increased and then deceased with foam quality (the ratio of gas volume to foam volume (gas + liquid). The optimal injection mode is co-injection 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 gas-blocking ability of polymer reinforced foam is better in high-permeability cores, which is beneficial for blocking high permeability zone. It should be also noted that under a certain ratio of oil to foam solution (about lower than 1 to 1), the presence of oil slowly decreased foam rate with increasing oil volume, but significantly increased half -life time, which is favorable for foam treatment in production well. This work highlights the difference between foam injection for gas blocking in production well and injection well, and emphasizes the use of polymer reinforced foam. Moreover, this work 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.