Page 396 - Enhanced Oil Recovery in Shale and Tight Reservoirs

Fracturing fluid flow back 367

The bottom hole injection pressure is 12,000 psi to simulate the water-
fracturing. After a typical volume of fracturing fluid is injected, flow back is
carried after some shut-in times. During the flow back and production, a
constant bottom hole pressure of 2000 psi is set.
To investigate the effect of shut-in on oil production, four shut-in times
of 0 (immediate flow back), 30, 60, and 300 days are chosen. Fig. 12.25
shows that a longer shut-in results in a higher initial oil rate, which is consis-
tent with most of field observations, and it also justifies the models used.
However, it also shows that shut-in does not affect the ultimate oil volume
produced. Fig. 12.26 shows the effect of SDP on the cumulative oil produc-
tion. It shows that when the permeabilities of matrix, NF, and HF are not
changed by the pore pressure, the total oil production is higher by 28%.
One believes water will dissipate away from the fracture-matrix interface
so that water blockage is mitigated. Fig. 12.27 shows the water saturations S w
at the two locations (2 and 8 inches away from HF) in the two cases of im-
mediate flow back (s0) and 300 days of shut-in (s300). First look at the water
saturations (two dotted lines) in the case of 300 days of shut-in. At the loca-
tion 2 inches away from the HF, S w keeps increasing until 50 days because

Figure 12.25 Effect of shut-in on oil production rate and cumulative oil production
volume.