Given the fact that diverting fracturing technique can improve the effective stimulation reservoir volume, and the currently-used temporary plugging materials of chemical particles and fibers are difficult to pass through sand-control completion tools and enter into fractures due to their solid nature, this work thus developed a novel temporary plugging agent (TPA) with multiphase transition properties at different temperatures. Laboratory and field experiments were both conducted to study its feasibility on industrial field applications.

Laboratory experiments were first carried out to investigate the properties of this TPA, including multiphase transition temperature and time, plugging strength, compatibility with other fluids, and core permeability damage, in order to guide the design of plugging agent dosage, fracturing construction parameters, and wellbore-fracture temperature. Then, field experiments were conducted to demonstrate its feasibility on actual field applications. Well A and Well R with almost the same geological and engineering conditions were chosen in this experiment where Well A adopted the developed novel technique and Well R, as a comparison well, adopted a conventional fracturing technique.

The results from the laboratory experiments indicated that the performance of this TPA met the requirements of industrial standards. With an increase in temperature, this TPA underwent a solution (liquid state) - gel (semi-solid state) - solution (liquid state) transition to meet the needs of different stages in a fracturing treatment, and its multiphase transition speed was controllable. Its plugging strength was positively correlated with its plugging length, with a gradient of 8.9MPa/m. This TPA had good compatibility with other fluids and little damage to rock permeability, only 2%, much less than 25% specified in the standard.

The results from the field experiments demonstrated that this innovative technique was feasible and effective. The construction curve of Well A indicated that the construction pressure increased by 3.1MPa and the formation broke again after injecting this TPA. The micro-seismic monitoring also supported this finding and showed that new fractures propagated to the north-by-east direction instead of the due west direction. Under the same production system, the initial daily gas production of Well A was 1.3 times that of Well R. After 100 days of production, the daily gas production of Well A was 1.5 times that of Well R.

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