Enhancing connectivity between injector and producer wells using sequenced stimulation

Abstract

Systems and processes for enhancing connectivity and/or permeability between injector and producer wells using sequenced stimulation. Methods of modeling same.

What is claimed is: 
     
         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.