Abstract Hydraulic fracturing of reservoirs which demonstrate a tendency for fluid retention, can result in low fluid recovery and poor productivity. In many cases, half or more of the load fluid is not retrieved. Pure carbon dioxide has been used as a carrier fluid in these reservoirs to avoid fluid retention. A new process for hydraulic fracturing gas reservoirs has been developed which uses the reservoir gas as a drive mechanism and a specially designed fluid slug to achieve miscible recovery of the treating fluid. The slug combines carbon dioxide with. certain hydrocarbons. The gelled hydrocarbon achieves high viscosity, even when mixed with CO2, This results in low friction, and good sand carrying capabilities. Some of the CO2 in solution in the hydrocarbon phase evolves as the pressure drops during leakoff, and creates a. miscible bank of enriched carbon dioxide between the fracturing fluid and the reservoir gas. Since the displacement process during flowback is miscible, virtually all of the fracturing fluid is recovered. The resultant high relative permeability to gas results in improved well productivity. This paper discusses the miscible processes examined that might be applied to fracture fluid recovery, the testing that was conducted to define a. workable process, the design procedure that was developed to ensure miscible recovery was achieved, and field results to verify the applicability of the process. Slim tube displacement experiments conducted with CO2 and specific hydrocarbon fracturing fluids, confirmed that miscibility can be achieved. Core displacement experiments on low permeability sandstone cores from the Glauconitic and other formations, using the CO2/hydrocarbon system, verified the low residual liquid saturations and high regain permeabilities. The core displacements also confirmed that simply having carbon dioxide in solution did not guarantee good results. Miscibility. between the reservoir fluid, and enriched carbon dioxide bank, and the fracturing fluid must be present to achieve effective recovery. Introduction Carbon dioxide has been used in the oil and gas industry for hydraulic fracturing applications since the early 1960' s, and has been well documented in the literature(l-14). Use of CO2 during hydraulic fracturing lowers interfacial tension and thus capillary retention of load fluid in tight formations. CO2 promotes rapid well cleanup due to gas drive in the reservoir and continuous gas lift in the wellbore. Additionally, high quality CO2 foams exhibit improved proppant carrying capacity and fluid loss control. Because of its unique properties, CO2 has been used in several different hydraulic fracturing applications. Initially, CO2 was used as an energizing component. Energized systems were defined as those containing less than 52%, by volume, CO2(5). Later, CO2 foam(4–6,8–10,14) and 100% liquid CO2(1,7,11,13) fracturing were introduced. In all applications, the objective was to reduce the amount of fluid left in the formation after fracturing. Foam minimized the amount of liquid left in the formation by reducing fluid loss, by gas drive assisted cleanup, and because the foam emulsion was comprised of very little liquid. But in low permeability reservoirs, where the size of the foam bubbles exceeded the size of the rock pore throats, phase segregation of the foam could occur(4).
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Dec 7, 2022
Alexey S Sorokin + 5
Open Access
