The present work presents the conceptual basis and experimental evaluation for a new technique to create insitu blocking foams in naturally fractured reservoirs by the injection of the foaming agent dispersed in a non-condensable gas stream. This work represents a further development of a previous paper (SPE-190219-MS; Ocampo et al, 2018) which presents a similar development for matrix dominated systems. Equivalent to previous work, the main objective is simplifying the operation and reducing costs for the deployment of EOR foams in gas injection based projects, and overcoming the limited reservoir volume of influence achieved by the surfactant alternated gas (SAG) technique.

An extensive and systematic experimental work was performed using fluids and low porosity naturally fractured rock representative of the Piedemonte area (Colombia, South America). The experiments were devised to investigate the effect of the dispersed chemical (surfactant) concentration and the gas velocity on the ability to create blocking foams at high pressure and temperature through the naturally fractured rock at a stress state representing open fracture conditions. The main physical mechanism behind this new technique is again the transfer of foamer droplets dispersed in the gas stream into the water present in the hydrocarbon reservoir. This transfer occurs because of the contrast in foamer concentration between the dispersed phase and the in-situ water. Results herein show reductions in gas mobility between 50% and 66%, along with increases in oil recovery factor between 10% and 34%, when the foamer chemical is dispersed in the gas stream, compared with the base gas flooding process performed on the described rock at residual oil and water saturations. This condition is obtained as far as the gas velocity is closed to rates equivalent to the velocities experienced near wellbore in the target reservoir, and the concentration of the active chemical is above 800 ppm (five times the concentration required to create blocking foam in the matrix system; Ocampo et al, 2018). Successful experiments with this new foam technique showed similar incremental recovery factors and stability periods as foams created by the SAG technique at higher chemical concentrations on the same rock fluid system.

The experimental results encouraged the progression and approval of a field pilot application of this foams technique this year in a Colombian Piedemonte gas condensate field characterized by the presence and dominance of the natural fractures both in the production and hydrocarbon gas injection performance.


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