METHOD OF INCREASING FRACTURE NETWORK COMPLEXITY AND CONDUCTIVITY
A complex fracture network within a hydrocarbon-bearing subterranean formation is created by first pumping a first fluid into the formation to create or enlarge a primary fracture and then pumping a second fluid into the formation wherein the second fluid contains a viscous material and the first fluid. By diverting the flow of the second flow, a secondary fracture is created having a directional orientation distinct from the directional orientation of the primary fracture.
1 . A method of fracturing a hydrocarbon-bearing subterranean formation penetrated by a wellbore which comprises, in a first stage:
(a) pumping a first fluid into the formation at a pressure sufficient to create or enlarge a primary fracture;
(b) pumping a second fluid into the formation, wherein the second fluid comprises the first fluid and a viscous material;
(c) creating or enlarging at least one secondary fracture having a directional orientation distinct from the directional orientation of the primary fracture by diverting the flow of the second fluid; and
(d) forming a complex fracture network by creating multiple fractures in the formation originating from the at least one secondary fracture.
2 . The method of claim 1 , wherein the viscous material is selected from the group consisting of viscoelastic surfactants, linear polymers, crosslinked polymers, surfactants, gelled hydrocarbons, and emulsion fluids and mixtures thereof.
3 . The method of claim 2 , wherein the viscous material is a gelled fluid of a viscoelastic surfactant, a linear polymer or a crosslinked polymer or a mixture thereof.
4 . The method of claim 2 , wherein the viscous material is selected from the group consisting of galactomannan gums, guars, derivatized guars, cellulose and cellulose derivatives, starch, starch derivatives, xanthan, derivatized xanthan and mixtures thereof.
5 . The method of claim 2 , wherein the viscous material is selected from the group consisting of crosslinked guars and crosslinked cellulosic derivatives and mixtures thereof.
6 . The method of claim 1 , wherein the viscous material is an emulsified fluid or a gelled oil.
7 . The method of claim 1 , wherein the first fluid or second fluid or both first fluid and second fluid further comprises a proppant.
8 . The method of claim 7 , wherein the proppant forms a partial monolayer within the created or enlarged fracture.
9 . The method of claim 1 , wherein the viscous material and the first fluid are present on the fly.
10 . The method of claim 7 , wherein during the first stage, at least one of the following factors varies:
(a) the size of the proppant within the first fluid or second fluid;
(b) the apparent specific gravity of the proppant within the first fluid and second fluid; or
(c) the shape of the proppant within the first fluid and second fluid.
11 . The method of claim 7 , wherein the apparent specific gravity of the proppant in the first fluid and/or the second fluid is less than or equal to 2.0.
12 . The method of claim 11 , wherein the apparent specific gravity of the proppant in the first fluid and/or the second fluid is less than or equal to 1.2.
13 . The method of claim 1 , wherein the viscous material further comprises an internal additive selected from the group consisting of biocides, tracers, proppants, nanocoating agents, surfactants, scale inhibitors, asphaltene inhibitors, hydrogen sulfide scavengers, nanoparticles, polymer breakers, VES breakers, microemulsions, fines migration control additives, fracture imaging materials, piezoelectric particles, metal particles, metal complexes, metal salts, fines control agents, solid acids, solid high pH buffers, salts, chelants, oxidizers, plant and fish oils, mineral oils, shape memory polymers, fibers, glass spheres, encapsulations, and combinations thereof.
14 . The method of claim 1 , wherein the viscosity ratio, Vr, representing the viscosity of the viscous material at 0.01 sec −1 and 80° F. to the viscosity of the first fluid at 0.01 sec −1 and 80° F. is 100 or greater.
15 . The method of claim 14 , wherein the viscosity ratio, Vr, is 10,000 or greater.
16 . The method of claim 15 , wherein the viscosity ratio, Vr, is 100,000 or greater.
17 . The method of claim 1 , wherein the viscous material has an average particle size from about 500 nm to about 50 cm.
18 . The method of claim 1 , wherein the permeability of the hydrocarbon-bearing subterranean formation is less than or equal to 0.1 mD.
19 . A method of fracturing a hydrocarbon-bearing subterranean formation penetrated by a wellbore which comprises, in a first stage:
(A) pumping a first fluid of low viscosity into the formation at a pressure sufficient to create or enlarge a primary fracture; and
(B) forming a complex fracture network comprising
(a) at least one secondary fracture having a directional orientation distinct from the directional orientation of the primary fracture; and
(b) a multiple of fractures originating from the at least one secondary fracture and having a directional orientation distinct from the direction orientation of the at least one secondary fracture
wherein the complex fracture network is formed by pumping a second fluid into the formation, wherein the second fluid comprises (i) the first fluid of low viscosity and (ii) a plurality of discrete bodies having a viscosity greater than the viscosity of the first fluid.
20 . The method of claim 19 , wherein the first fluid and the plurality of discrete bodies are present on the fly.
21 . The method of claim 19 , wherein the pumping of the first fluid and the second fluid reduces or minimizes conductivity-limited choke points within the complex fracture network.
22 . A method of hydraulically fracturing a hydrocarbon-bearing subterranean formation penetrated by a wellbore which comprises, in a first stage:
(a) pumping a first fluid of low viscosity into the formation at a pressure sufficient to create or enlarge a primary fracture;
(b) pumping a second fluid into the formation, wherein the second fluid is prepared by adding to the first fluid a plurality of discrete bodies having a viscosity greater than the viscosity of the first fluid;
(a) creating or enlarging at least one secondary fracture having a directional orientation distinct from the directional orientation of the primary fracture by diverting the flow of the second fluid; and
(b) forming a complex fracture network through the addition of a diverting fluid into the formation and creating multiple fractures in the formation originating from the at least one secondary fracture wherein the diverting fluid is prepared by adding to the first fluid a plurality of discrete bodies having a viscosity greater than the viscosity of the first fluid and wherein the multiple fractures are created by the action of the plurality of discrete bodies of viscous material in the diverting fluid.
23 . The method of claim 22 , wherein the second fluid and the diverting fluid are the same.
24 . The method of claim 22 , wherein the pumping of the first fluid, the second fluid and the diverting fluid reduces or minimizes conductivity-limited choke points within the complex fracture network.
25 . The method of claim 22 , wherein the permeability of the subterranean formation is less than or equal to 0.1 mD.
26 . A method of fracturing a hydrocarbon-bearing subterranean formation penetrated by a well to create a complex fracture network, the method comprising pumping into the formation, in a first stage a, first fluid and at least one second fluid, wherein the at least one second fluid is comprised of a viscous material and the first fluid, wherein:
(a) a primary fracture is created or enlarged by pumping into the formation the first fluid;
(b) at least one secondary fracture perpendicular and/or orthogonal to the primary fracture is created by diverting the flow of the at least one second fluid; and
(c) a complex fracture network comprising a series of fractures is created by continuously diverting the flow of the at least one second fluid through the formation and further wherein either:
(i) the surface area ratio (Sr), defined by Scf/Spf wherein Scf is the surface area of the complex fracture network and Spf is the surface area over the primary fracture, is greater when the first fluid and second fluid are pumped into the formation versus when only the first fluid is pumped into the formation; or
(ii) the conductivity ratio (Cr) defined by Ccf/Cpf, wherein Ccf is the conductivity of the complex fracture network and Cpf is the conductivity of the planar fracture divided by 1000 is greater when the first fluid and the at least one second fluid are pumped into the formation versus when only the first fluid is pumped into the formation.
27 . The method of claim 25 , wherein the first fluid is a brine.
28 . The method of claim 25 , wherein the first fluid contains a friction reducing agent.
29 . The method of claim 25 , wherein the conductivity within the complex fracture network ranges from nano-darcies at the tip of the fractures to milli-darcies to the primary fracture.
30 . The method of claim 25 , wherein the rate of pumping of the first fluid and/or the second fluid is varied during the fracturing.
31 . The method of 25, wherein the subterranean formation is shale.
32 . A method of generating diversion during the fracturing of a subterranean formation penetrated by a wellbore comprising:
(a) introducing into the wellbore, at a rate and pressure sufficient to fracture the subterranean formation, a brine fracturing fluid comprising:
(i) a lower viscosity fluid stream; and
(ii) a plurality of discrete bodies of a higher viscosity material; and
(b) diverting the lower viscosity fluid stream by action of the discrete bodies of the higher viscosity material.
33 . The method of claim 30 , wherein the discrete bodies generate viscosity in the lower viscosity fluid stream in narrow fractures and under high fracture wall shear.