Well treatment

Abstract

Rapidly pulsed injection fracture acidizing. A method comprises rapidly pulsed injection of a high reactivity fracture treatment fluid mode or substage alternated with one or more low reactivity treatment fluid modes or substages.

We claim: 
     
         1 . A method comprising
 injecting a treatment stage fluid into a subterranean formation above a fracturing pressure to form a fracture in the formation;   successively alternating reactivity modes in the treatment stage fluid, in either order, between at least first and second reactivity modes to react with carbonate in the formation at different rates or times to unevenly etch surfaces of the fracture;   sustaining injection of the treatment stage fluid during each of the first and second reactivity modes for a period of time from 5 seconds up to 2.5 minutes;   repeating the successive alternation of reactivity modes for a plurality of cycles; and   reducing pressure to facilitate fracture closure and form interconnected, hydraulically conductive channels between opposing fracture surfaces.   
     
     
         2 . The method of  claim 1 , wherein one of the first and second reactivity modes comprises a reactant reactive with the carbonate in the formation and the other of the first and second reactivity modes comprises the reactant at a lesser concentration, or in a less reactive form, or is free of the reactant. 
     
     
         3 . The method of  claim 2 , wherein the reactant is selected from the group consisting of mineral acids, organic acids, chelants and combinations thereof. 
     
     
         4 . The method of  claim 1 , further comprising:
 successively alternating viscosity modes in the treatment stage fluid, in either order, between at least first and second viscosity modes, wherein one of the first and second viscosity modes has a higher viscosity than the other;   sustaining injection of the treatment stage fluid during each of the first and second modes for a period of time from 5 seconds up to 2.5 minutes; and   repeating the successive alternation of viscosity modes for a plurality of cycles.   
     
     
         5 . The method of  claim 4 , wherein the first and second reactivity modes coincide with the first and second viscosity modes, respectively. 
     
     
         6 . The method of  claim 5 , wherein the relatively low viscosity modes form fingers penetrating into the high viscosity modes in the fracture. 
     
     
         7 . The method of  claim 6 , wherein the fingers break through the penetrated high viscosity mode into a preceding low viscosity mode. 
     
     
         8 . The method of  claim 5 , wherein the first reactivity and viscosity modes have a high viscosity and low reactivity relative to the second reactivity and viscosity mode. 
     
     
         9 . The method of  claim 8 , wherein the first reactivity and viscosity modes comprises a viscoelastic diverting agent and has a viscosity higher than that of the second reactivity and viscosity modes. 
     
     
         10 . The method of  claim 1 , wherein the treatment stage fluid comprises a gel, a cross-linked gel, an emulsion, a foam, or a combination thereof. 
     
     
         11 . The method of  claim 1 , wherein the treatment stage fluid comprises a solid material slurried in a carrier fluid. 
     
     
         12 . The method of  claim 1 , wherein the treatment stage fluid comprises a plurality of polyolefin beads having an average particle size distribution of less than or equal to about 1000 microns (˜20 mesh). 
     
     
         13 . The method of  claim 1 , wherein one of the first and second reactivity modes comprises asphaltene, polylactic acid, latex, or a combination thereof, and the other one of the first and second reactivity modes comprises a multivalent cation. 
     
     
         14 . The method of  claim 1 , wherein one of the first and second reactivity modes comprises an aqueous carrier fluid, and the other one of the first and second reactivity modes comprises an oleaginous carrier fluid. 
     
     
         15 . The method of  claim 1 , wherein the treatment stage fluid comprises a water-in-oil emulsion wherein a reactant with carbonate in the formation is in a dispersed phase. 
     
     
         16 . The method of  claim 1 , further comprising gelling the first reactivity mode, the second reactivity mode or both in the fracture. 
     
     
         17 . The method of  claim 1 , wherein a volumetric ratio of the first reactivity mode to the second reactivity mode is from about 1:99 to about 99:1. 
     
     
         18 . The method of  claim 1 , wherein the sustained periods of time are from about 5 seconds to about 1 minute. 
     
     
         19 . The method of  claim 1 , further comprising injecting a pad stage in advance of the treatment fluid stage, injecting a terminal flush stage, or a combination thereof. 
     
     
         20 . A method comprising:
 injecting a treatment stage fluid above a fracturing pressure to form a fracture in a subterranean formation penetrated by a wellbore;   successively alternating modes in the treatment stage fluid, in either order, between at least first and second modes;   wherein the first modes have a high viscosity relative to the second modes for viscous fingering of the second mode into the first mode in the fracture;   wherein the second modes have high reactivity with carbonate in the formation relative to the first mode to unevenly etch surfaces of the fracture;   sustaining injection of the treatment stage fluid during each of the first and second modes for a period of time from 5 seconds up to 2.5 minutes;   repeating the successive alternation of modes for a plurality of cycles; and   reducing pressure to facilitate fracture closure and form interconnected, hydraulically conductive channels between opposing fracture surfaces.   
     
     
         21 . The method of  claim 20 , wherein the viscous fingering from one of the second modes breaks through one of the first modes into another one of the second modes. 
     
     
         22 . A system, comprising:
 a subterranean formation penetrated by a wellbore;   a treatment fluid stage disposed in the wellbore, the treatment fluid stage comprising a plurality of first mode substages disposed in the wellbore in an alternating sequence with a plurality of second mode substages, wherein the first mode substages have a high viscosity relative to the second mode substages and wherein the second mode substages have a high reactivity with carbonate in the formation relative to the first mode substages; and   a pump system to continuously deliver the treatment fluid stage from the wellbore to the formation at a pressure above fracturing pressure to inject the treatment fluid stage into a fracture in the formation, and at a rate wherein each substage is injected into the formation over a period of time from 1 second to 2.5 minutes.   
     
     
         23 . A system, comprising:
 a subterranean formation penetrated by a wellbore;   means for injecting a treatment stage fluid above a fracturing pressure to form a fracture in the formation;   means for successively alternating modes in the treatment stage fluid, in either order, between at least first and second modes;   wherein the first modes have a high viscosity relative to the second modes for viscous fingering of the second mode into the first mode in the fracture;   wherein the second modes have high reactivity with carbonate in the formation relative to the first mode to unevenly etch surfaces of the fracture;   means for sustaining injection of the treatment stage fluid during each of the first and second modes for a period of time from 5 seconds up to 2.5 minutes;   means for repeating the successive alternation of modes for a plurality of cycles; and   means for reducing pressure to facilitate fracture closure and form interconnected, hydraulically conductive channels between opposing fracture surfaces.