ENHANCING CONNECTIVITY BETWEEN INJECTOR AND PRODUCER WELLS USING SEQUENCED STIMULATION

1 . A method of modeling enhancing connectivity in a subterranean geologic formation between an injector well and a producer well, comprising:

(a) inputting thermodynamic properties of one or more stimulation fluids;

(b) inputting estimated total porosity of natural fractures encountered in the subterranean geologic formation estimated from a borehole logging tool or from geologic settings of the subterranean geologic formation; and

(c) estimating enhancement of connectivity in the subterranean geologic formation after artificially stimulating the subterranean geologic formation with the stimulation fluid to form a thermal lattice therein by sequentially:

(i) pumping a first volume of one or more fluids to tensile fracture the subterranean geologic formation, generating a downhole pressure that produces a stress on the subterranean geologic formation exceeding a minimum horizontal stress of the subterranean geologic formation, from the injector well to a producer well, the producer well extending from the surface to the subterranean geologic formation;

(ii) pumping the one or more fluids in a pulsing mode to cause fatigue to any existing natural fractures intersecting fractures caused by the tensile fracture, or to natural non-fractured rock, the pulsing mode having a pulse amplitude below the minimum horizontal stress of the subterranean geologic formation with frequency controlled by rock fabric of the subterranean geologic formation and bottom hole static temperature;

(iii) pumping a second volume of the one or more fluids during an injection period as a hydro-shearing stage, the second pump volume based on an estimated total porosity of natural fractures encountered in the subterranean geologic formation estimated from a borehole logging tool or from geologic settings of the subterranean geologic formation.

2 . The method of modeling of claim 1 comprising modeling a return fluid annulus surface temperature.

3 . The method of modeling of claim 1 comprising modeling a temperature of the one or more stimulation fluids at a stimulation fluid injection location.

4 . The method of modeling of claim 1 comprising modeling a fluid temperature at surface, at or near a fluid injection position.

5 . The method of modeling of claim 1 comprising modeling a standpipe pressure.

6 . The method of modeling of claim 1 comprising modeling a fluid pressure at surface, at or near fluid injection position.

7 . The method of modeling of claim 1 comprising modeling an annular velocity of the one or more stimulation fluids.

8 . The method of modeling of claim 1 comprising modeling a density of the one or more stimulation fluids at surface, at injection point.

9 . The method of modeling of claim 1 comprising producing graphical displays of one or more of stimulation fluid pressure, stimulation fluid temperature, stimulation fluid state curve in p-H diagram, stimulation fluid density, and stimulation fluid specific heat.

10 . A method of modeling enhancing permeability in a subterranean geologic formation between an injector well and a producer well, comprising:

(a) inputting thermodynamic properties of one or more stimulation fluids;

(b) inputting estimated total porosity of natural fractures encountered in the subterranean geologic formation estimated from a borehole logging tool or from geologic settings of the subterranean geologic formation; and

(c) estimating enhancement of permeability in the subterranean geologic formation after artificially stimulating the subterranean geologic formation with the stimulation fluid to form a thermal lattice therein by sequentially:

(i) pumping a first volume of one or more fluids to tensile fracture the subterranean geologic formation, generating a downhole pressure that produces a stress on the subterranean geologic formation exceeding a minimum horizontal stress of the subterranean geologic formation, from the injector well to a producer well, the producer well extending from the surface to the subterranean geologic formation;

(ii) pumping the one or more fluids in a pulsing mode to cause fatigue to any existing natural fractures intersecting fractures caused by the tensile fracture, or to natural non-fractured rock, the pulsing mode having a pulse amplitude below the minimum horizontal stress of the subterranean geologic formation with frequency controlled by rock fabric of the subterranean geologic formation and bottom hole static temperature;

(iii) pumping a second volume of the one or more fluids during an injection period as a hydro-shearing stage, the second volume based on an estimated total porosity of natural fractures encountered in the subterranean geologic formation estimated from a borehole logging tool or from geologic settings of the subterranean geologic formation.

11 . The method of modeling of claim 10 comprising modeling a return fluid annulus surface temperature.

12 . The method of modeling of claim 10 comprising modeling a temperature of the one or more stimulation fluids at a stimulation fluid injection location.

13 . The method of modeling of claim 10 comprising modeling a fluid temperature at surface, at or near a fluid injection position.

14 . The method of modeling of claim 10 comprising modeling a standpipe pressure.

15 . The method of modeling of claim 10 comprising modeling a fluid pressure at surface, at or near fluid injection position.

16 . The method of modeling of claim 10 comprising modeling an annular velocity of the one or more stimulation fluids.

17 . The method of modeling of claim 10 comprising modeling a density of the one or more stimulation fluids at surface, at injection point.

18 . The method of modeling of claim 10 comprising producing graphical displays of one or more of stimulation fluid pressure, stimulation fluid temperature, stimulation fluid state curve in p-H diagram, stimulation fluid density, and stimulation fluid specific heat.