Hydrocarbon recovery process

A method for increasing the recovery of crude oil from a reservoir comprising at least one oil-bearing porous subterranean formation having a permeability of greater than 10 millidarcies and having at least one injection well and at least one production well penetrating the formation wherein (a) crude oil and connate water are present within the pore space of the formation rock, and (b) the crude oil that is present in the formation has an American Petroleum Institute (API) gravity of less than 30°, a viscosity under reservoir conditions of greater than 1 centipoise, and undissolved solids suspended therein in an amount of at least 0.05% by weight, the method comprising:

• (A) injecting an injection water into the formation via the at least one injection well wherein the injection water has undissolved solids suspended therein in an amount of at least 0.05% by weight, a total dissolved solids content (TDS) of 30,000 ppm or less, and a ratio of the total multivalent cation content of the injection water to the total multivalent cation content of the connate water of less than 0.9;
• and
• (B) producing from the at least one production well an emulsion having undissolved solids suspended therein in an amount of at least 0.05% by weight (0.5 kg/m3) of emulsion.

A method for increasing the recovery of crude oil from a reservoir comprising at least one porous subterranean formation having a permeability of greater than 10 millidarcies wherein (a) crude oil and connate water are present within the pores of the formation, (b) the crude oil that is present in the formation has an API gravity of less than 30°, a viscosity under reservoir conditions of greater than 1 centipoise, and particulate solids having an average particle diameter of less than 2 microns suspended therein in an amount of at least 0.01% by weight (0.1 kg/m3), and (c) an injection water is injected into the formation for forming a water-in-oil emulsion with the crude oil that is contained within the pores of the formation, wherein the injection water is selected by:

• (a) determining the multivalent cation content of the connate water;
• and
• (b) selecting an injection water having (i) a total dissolved solids content of less than 30,000 ppm, (ii) a total multivalent cation content such that the ratio of the total multivalent cation content of the injection water to the total multivalent cation content of the connate water is less than 0.9, and (iii) at least 0.05% by weight (0.5 kg/m3) of particulate solids having an average particle diameter of less than 2 microns suspended therein.