Figure 1.
The multi-point pressure physical model.
Figure 2.
The double tube physical model.
Figure 3.
The single tube experimental model.
Figure 4.
The visual simulation experimental flow chart.
Figure 5.
The morphology and size distribution of typical DPG particles.
(A) The TEM morphology of nano-size DPG particles; (a) Nano-size DPG particles with an average size of approximately 108 nm; (B) The TEM morphology of micron-size DPG particles; (b) Nano-size DPG particles with an average size of approximately 5.6 µm; (C) mm-Size DPG particles with an average size of approximately 3.2 mm.
Figure 6.
The pressure changes at different stages.
Figure 7.
The profile improvement capacity of DPG particles.
Table 1.
Disproportionate permeability reduction of DPG particles.
Figure 8.
Visual simulation results in a flat panel sand model.
(a) model; (b) saturating water; (c) saturating oil; (d) water flooding until water cut is up to 98%; (e) injection of DPG particles for 6 min; (f) injection of DPG particles for 9 min; (g) injection of DPG particles for 15 min; (h) injection of DPG particles for 20 min; (o) water flooding until water cut is up to 98% again.
Figure 9.
Visual simulation results in etched glass model.
(a) model; (b) saturating water; (c: saturating oil; (d) water flooding until water cut is up to 98%; (e) retention in larger pore space; (f) directly plugging the small pore throat; (g) segregated flow of oil and water pathway; (h) adsorption on the surface; (o) water flooding until water cut is up to 98% again.
Figure 10.
DPG particle distribution in etched glass model at different magnifications.
(a)∼(d): 40× magnification; (e)∼(f): 100× magnification.
Figure 11.
Schematic illustration for the enhanced oil recovery mechanism.
(a) oil distribution in the initial stage of reservoir development; (b) a high permeability zone formed after long-term water flooding; (c) injection of DPG particles for profile control; (d) DPG particles deform and pass through pores; (c) water flooding after the treatment.