The design of new dual-function inhibitors simultaneously preventing hydrate formation and corrosion is a relevant issue for the oil and gas industry. The structure-property relationship for a promising class of hybrid inhibitors based on waterborne polyurethanes (WPU) was studied in this work. Variation of diethanolamines differing in the size and branching of N-substituents (methyl, n-butyl, and tert-butyl), as well as the amount of these groups, allowed the structure of polymer molecules to be preset during their synthesis. To assess the hydrate and corrosion inhibition efficiency of developed reagents pressurized rocking cells, electrochemistry and weight-loss techniques were used. A distinct effect of these variables altering the hydrophobicity of obtained compounds on their target properties was revealed. Polymers with increased content of diethanolamine fragments with n- or tert-butyl as N-substituent (WPU-6 and WPU-7, respectively) worked as dual-function inhibitors, showing nearly the same efficiency as commercial ones at low concentration (0.25 wt%), with the branched one (tert-butyl; WPU-7) turning out to be more effective as a corrosion inhibitor. Commercial kinetic hydrate inhibitor Luvicap 55 W and corrosion inhibitor Armohib CI-28 were taken as reference samples. Preliminary study reveals that WPU-6 and WPU-7 polyurethanes as well as Luvicap 55 W are all poorly biodegradable compounds; BODt/CODcr (ratio of Biochemical oxygen demand and Chemical oxygen demand) value is 0.234 and 0.294 for WPU-6 and WPU-7, respectively, compared to 0.251 for commercial kinetic hydrate inhibitor Luvicap 55 W. Since the obtained polyurethanes have a bifunctional effect and operate at low enough concentrations, their employment is expected to reduce both operating costs and environmental impact.

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.

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.

Rapid hydrate formation and high storage capacity are two key parameters in commercializing hydrate-based solidified natural gas technology. Surfactants are known as the most effective additives to accelerate the kinetics of gas hydrate formation under different conditions. This research introduces an efficient class of anionic surfactants – carboxyl-sulfonated surfactant (CSS) – as gas hydrate promoters for the first time. To that end, CSSs with different alkyl chain lengths were synthesized, and their promotion effect on methane hydrate formation was evaluated in static and dynamic conditions. Those CSSs with 10 carbon atoms provided a maximum conversion of 88.4% at 500 ppm, higher than that of sodium dodecyl sulfate (87.9%). However, those with 12 carbon atoms were selected as the optimal promoter in terms of kinetic constants. The results of a high-pressure autoclave experiments revealed that the hydrophilic–hydrophobic balance of CSSs strongly affected their promotional activity. CSSs with a short alkyl chain had lower promotion efficiency as they could not increase the solubility of gas in water, especially under static conditions. Additionally, molecular dynamic simulations showed that the length of the alkyl chain directly influences the performance of promoter molecules because a longer hydrophobic tail can attract more methane molecules from the solution to supply them for the growing hydrate surface. Moreover, the CSSs with 12 carbon atoms aggregated into a stable micelle during hydrate formation according to the hydrophobic interaction, which attracted methane molecules around its hydrophobic tail and enhanced the hydrate growth rate. These findings can be useful in developing novel surfactants for energy-efficient methane storage in gas hydrates.