Page 337 - Enhanced Oil Recovery in Shale and Tight Reservoirs

310 Enhanced Oil Recovery in Shale and Tight Reservoirs

11.2 Description of a base shale model
Compared with spontaneous imbibition, much less work has been
done for forced imbibition in shale and tight reservoirs. To study the forced
imbibition EOR performance, relatively more numerical simulation work
will be discussed. To facilitate the discussion, a base simulation model is first
described.
In the Najafabadi et al. (2008) experiment, a system of matrix and frac-
tures was flooded sequentially by water, an alkaline solution, and an
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alkaline-surfactant solution. Nine Texas cream cores 1 1 1 each
core were put together to form a fractured system with the apertures
between neighboring blocks representing fractures, as shown in Fig. 11.1
by simulation grids. There were two fractures parallel to the flow direction
and four fractures perpendicular. The fracture width was about 1 mm
(0.003281 ft). The model grid parameters are reported in Table 11.1. The
initial water saturation is 0.14. The oil viscosity is 10.5 cP.
The estimated pore volume of the core was 120 mL. The injection
scheme in the experiment was: 0.71 PV water injection with 4.8 wt.%
NaCl, 1.6 PV (from 0.71 to 2.4 PV) alkali injection with 1 wt.% sodium
metaborate and 3.8 wt.% NaCl followed by 0.97 PV (from 2.4 PV to
3.37 PV) alkaline-surfactant injection with 1.5 wt.% PetroStep S-1 and

Figure 11.1 Model grid with initial water saturation, fractures, an injector (Inj), and a
producer (pro).