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A considerable portion of heavy oil resides in thin formations. In such reservoir environments, thermal recovery methods tend to be neither effective nor economical, due to significant heat loss and water resource requirements. The methane huff-n-puff process for enhancing heavy oil recovery in thin formations is an alternative that has the advantages of availability of resources and economic efficiency. However, the principal problem with such a process is the high mobility of the gas phase, relative to the oil phase, during the production cycle. In order to overcome this limitation, this paper presents a new enhanced methane injection technique, called the foamy oil-assisted methane huff-n-puff method (FOAM H-n-P). In this process, an oil-soluble foaming agent and methane are injected in a cyclic manner, but in two separate slugs. The methane provides the solution gas drive energy, and the presence of the foaming agent promotes the formation of an in situ foamy oil by trapping the released gas, which significantly enhances the effectiveness of the solution gas drive mechanism. A new experimental procedure was developed to prove that the selected foaming agent has an effective foaminess in conventional heavy oil, and to investigate, quantitatively, the effects of various process parameters on foamy oil stability in the FOAM H-n-P process. A series of experiments were conducted to evaluate FOAM H-n-P performance and to examine the effect of various foaming agent injection parameters on oil recovery. The experimental results show that foaming oil stability increases with greater foaming agent concentration, greater initial heavy oil height, a higher degree of gas bubble dispersiveness, and smaller dispersed gas bubble size. The FOAM H-n-P process can substantially improve heavy oil recovery performance. The most efficient case increases oil recovery by 43.29% OOIP, compared to the traditional methane huff-n-puff process. The above knowledge will have significant importance for the development of heavy oil resources in thin reservoirs. [ABSTRACT FROM AUTHOR]

• Non-equilibrium swelling experiments were carried out of HO-gas systems. • Image analysis technique was developed to quantify the effectiveness of foamy oil. • A novel model is proposed to calculate the non-equilibrium properties of foamy oil. • The variation of apparent density/compressibility can be divided into three stages. • CH 4 is preferable for inducing foamy oil behavior than CO 2 and C 3 H 8. The foamy oil phenomenon has a positive influence on cyclic solvent injection (CSI) processes for oil recovery because it affects the properties of heavy oil (HO). However, there is still a lack of mathematical methods and basic experimental data for the physical properties of foamy oil during CSI processes. The effects of injection gas type and mole fraction on foamy oil behavior and non-equilibrium properties are still not well understood. In this study, a new type of non-equilibrium swelling experiment was proposed to determine the properties of foamy oil induced by CH 4 , CO 2 , and C 3 H 8. The effects of gas type, mole fraction, and pressure were analyzed experimentally, and foamy oil behavior was observed by utilizing a high-pressure cell that was designed specifically for this purpose. Then, a mathematical model was developed to calculate the non-equilibrium properties of foamy oil. The results show that higher pressures are needed to dissolve and disperse gas in HO to induce foaming, and the lifetime of foamy oil increases with increasing mole fraction of injected gas. The formation of foamy oil can effectively swell HO, and the swelling factor (SF b) and pseudo-swelling factor (SF pb) increase gradually with increasing mole fraction of injected gas. Compared to CO 2 and C 3 H 8 , CH 4 is advantageous for inducing foamy oil phenomena. Lower apparent density and higher compressibility were observed in the HO-CH 4 systems than in the HO-CO 2 and HO-C 3 H 8 systems at the same gas mole fractions. [ABSTRACT FROM AUTHOR]

• The OSFA-CMSI process is a potentially feasible method for heavy oil recovery. • The designed setup can better study CSI-based processes under reservoir conditions. • The OSS plays a more important role than C 3 H 8 in the OSFA-CMSI processes. • The solvent mixture should be injected at or near to its dew point conditions. • The OSFA-CMSI process may be more suitable to post-CHOPS reservoirs. Cyclic solvent injection (CSI) has shown a significant potential to enhance heavy oil recovery after primary production. However, the principal limitation of this process is quick solvent liberation due to the high gas mobility and oil viscosity regainment during the production period. In this study, a novel variation of CSI, called oil-soluble surfactant-assisted cyclic mixed solvent injection (OSFA-CMSI), is proposed to overcome these limitations. During this process, an oil-soluble surfactant and a specially designed solvent mixture (produced gas and propone) are cyclically injected into reservoirs in two separate slugs. The designed solvent mixture renders the process technically sound and effectively viable, and the surfactant induces the formation of an effective foamy oil flow by dispersing the released or undissolved gaseous solvent during the production period. A series of experiments were performed by using a patented core holder to prove the viability of the OSFA-CMSI process and to study the effects of the solvent composition, pressure depletion rate, wormhole presence, and confining pressure on the OSFA-CMSI performance. The experimental results show that the selected oil-soluble surfactant FlourN™ 20158M can create an effective foamy oil phenomenon in heavy oil, which contributes to the enhanced oil swelling effect and gas dispersion that delays the formation of free gas. The OSFA-CMSI process is a potentially feasible method for heavy oil recovery after primary production, especially for post-cold heavy oil production with sand reservoirs. The most efficient test improves oil recovery by 41.64% of the original oil in place (OOIP) compared to that of the traditional CSI process. There is an optimal C 3 H 8 content in the solvent mixture (46 mol% in this study), beyond which the performance of the OSFA-CMSI process worsens. The solvent mixture should be injected at or near its dew point without any liquefaction to achieve maximum solubility and generate an effective foamy oil flow. Increases in the pressure depletion rate and confining pressure are beneficial when using OSFA-CMSI to enhance the oil recovery factor over a short production time but result in lower final oil recovery factors. [ABSTRACT FROM AUTHOR]