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).

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.

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.