Page 495 - Enhanced Oil Recovery in Shale and Tight Reservoirs

Other enhanced oil recovery methods 459

the amount of oxidizing agent was the same in the two solutions. Probably,
the adsorption of anionic surfactant in the blend solution retarded the calcite
dissolution. The dissolution resulted in permeability increase from 54 to
78 mD on the average from three tests. The permeability increase was owing
to the microfractures generated or widened on the big fracture surface. The
dissolution did not weaken the rock hardness, while HCl decreased the
hardness from 200 to 70 MPa, as HCl dissolved more calcite than the blend.
The softening of rock might cause mud generation and proppant embed-
ment. However, the dissolution decreased the fracture conductivity by
30%e60%, because the continued flow of the blend solution made the
proppant packing tighter. Fortunately, fracture conductivity is generally
not the limiting resistance to production; the resistance in the matrix dom-
inates the flow. The solution having the oxidizing agent alone could not
produce oil. With just the oxidizing agent in brine, there was some calcite
dissolution, but no oil was released by aging a shale core (spontaneous imbi-
bition). In a combination of the organic solvent and the oxidizing agent, the
oxidizing agent reacted with the shale and dissolved some calcite. But no oil
was produced from the shale.
The organic solvent solubilized oil and oil residues like asphaltene. The
spontaneous imbibition type of experiments showed that for a solution of
organic solvent alone, only organic solvent floated at the top of the solution,
but no oil was produced from the shale. There was no interaction between
the organic solvent and the shale.
When the anionic surfactant and oxidizing agent were mixed, there was
some wettability alteration, but the calcite dissolution became smaller than
the case with oxidizing agent alone, because the surfactant covered some
of the calcite.
When the anionic surfactant and organic solvent were mixed, the wetta-
bility was altered, but no oil was released in spontaneous imbibition.
When these three components were mixed, the wettability was altered,
oil was released, and the calcite was dissolved.
Field trials were performed in several Eagle Ford wells in South Texas.
Individual chemicals in 2% NaCl brine were used as a preload to mitigate
frac hit. The preload volume of 3000 e 20,000 bbls were pumped at a
rate of 2e5 bbls/min, followed by an average shut-in time of 2e5 weeks.
A dozen of treated wells showed strong well performance. The incremental
cumulative oil and water production were 20,000 bbls and 12,000 bbls,
respectively, with 60% of injected water returned in a period of 8 months
after 5 weeks of soak. Note that the laboratory tests showed that the
shut-in time of 2 days was enough.