Compound cluster placement in fractures

Abstract

Proppant cluster placement in fractures with foamed carrying fluid. A formation treatment method includes injecting a treatment fluid stage, having a particulate-containing substage containing a self-agglomerating solid composition and a foamed carrying fluid, above a fracturing pressure, and alternating pulses of a pumping parameter to transform the self-agglomerating composition into a channelized solids pack, and closing the fracture. Also disclosed are methods of modeling a fracture treatment interval for such a method, and methods of treatment and systems to treat with such a treatment fluid stage, wherein solid particulate-rich substages are larger than the solid particulate-lean substages to form particulate-rich island regions, an interconnected network of open channel regions between the island regions and the island regions are channelized to form particulate clusters within the island regions separated from adjacent particulate clusters by open voids in the island regions.

We claim: 
     
         1 . A method to treat a subterranean formation penetrated by a wellbore, comprising:
 providing a treatment fluid stage comprising a particulate-containing substage comprising a self-agglomerating solid composition and a foamed carrying fluid;   injecting the treatment fluid stage above a fracturing pressure to place the treatment fluid stage in a fracture in the formation according to pumping parameters selected from composition of the particulate-containing substage and pumping rate of the treatment fluid stage;   alternating pulses of at least one of the pumping parameters to transform the self-agglomerating solid composition in the fracture into a channelized solids pack comprising clusters having a high concentration of solids, wherein the clusters are separated by open voids having a substantially reduced concentration of solids between the clusters; and   closing the fracture onto the clusters.   
     
     
         2 . The method of  claim 1 , wherein the self-agglomerating solids composition comprises fiber. 
     
     
         3 . The method of  claim 1 , wherein the transformation of the solid composition comprises destabilization of the foamed carrying fluid. 
     
     
         4 . The method of  claim 1 , wherein the at least one alternated pumping parameter comprises foam quality of the carrying fluid between alternate pulses within the particulate-containing substage. 
     
     
         5 . The method of  claim 1 , wherein the at least one alternated pumping parameter comprises foam quality of the carrying fluid between alternate pulses within the particulate-containing substage, wherein the foam quality (volume percent gas) is alternated between values different by at least 5 percent. 
     
     
         6 . The method of  claim 1 , wherein the at least one alternated pumping parameter comprises a concentration between alternate pulses within the particulate-containing substage of a fluid rheology component [defined as anything that changes fluid rheology, such as, for example, a viscosifier, breaker, crosslinker, decrosslinker, etc. before closing the fracture. 
     
     
         7 . The method of  claim 1 , wherein the at least one alternated pumping parameter comprises a concentration of breaker between alternate pulses, wherein the breaker reduces the viscosity of the carrying fluid before closing the fracture. 
     
     
         8 . The method of  claim 1 , wherein the at least one alternated pumping parameter is selected from the group consisting of crosslinker concentration, crosslinker delay agent concentration, decrosslinker concentration, fiber concentration, proppant concentration, fluid loss additive concentration, clay stabilizer concentration, pH adjusting agent concentration, and combinations thereof. 
     
     
         9 . The method of  claim 1 , wherein closing the fracture comprises shutting in the wellbore and waiting for the fracture to close. 
     
     
         10 . The method of  claim 1 , wherein closing the fracture comprises forced fracture closure. 
     
     
         11 . The method of  claim 1 , wherein the treatment fluid stage comprises alternating a plurality of the solid particulate-containing substages with solid particulate-lean substages, wherein a volume of each of the solid particulate-containing substages is larger than a respective volume of an adjacent one of the particulate-lean substages. 
     
     
         12 . A fracture treatment method for a subterranean formation penetrated by a wellbore, comprising:
 considering closure stress and stiffness of an interval of the formation;   modeling the interval based on the closure stress and stiffness of the interval to determine a minimum coverage of propped regions in a fracture in the interval and maximum open channel breadth between the propped regions to inhibit collapse of the open channels;   formulating a treatment fluid stage comprising alternating solid particulate-rich and solid particulate-lean substages, wherein at least a portion of the particulate-rich substage comprises a self-agglomerating solid composition and a foamed carrying fluid, wherein a volume of each of the particulate-rich substages is larger than a respective volume of an adjacent one of the particulate-lean substages;   injecting the formulated treatment fluid stage above a fracturing pressure into the formation by alternatingly injecting the solid particulate-rich and solid particulate-lean substages into the fracture;   forming a plurality of particulate-rich island regions in the fracture to provide at least the minimum coverage of propped regions as determined by the modeling;   forming an interconnected network of open channel regions between the island regions in the fracture having a channel breadth less than the maximum channel breadth as determined by the modeling;   reducing pressure in the fracture to close the fracture propped on the island regions; and   hydraulically conducting fluid flow through the open channel regions between the formation and the wellbore.   
     
     
         13 . The method of  claim 12 , further comprising channelizing the solid particulate rich island regions in situ in the fracture to form solid particulate clusters within the island regions separated from adjacent solid particulate clusters by open voids within the island regions. 
     
     
         14 . The method of  claim 1 , wherein the solid particulate-rich substages and the solid particulate-lean substages in the treatment stage fluid have an overall volumetric ratio from 60:40 to 95:5. 
     
     
         15 . A method to treat a subterranean formation penetrated by a wellbore, comprising:
 injecting a treatment fluid stage above a fracturing pressure into the formation to distribute a mixture of a solid particulate in a fracture;   alternatingly injecting solid particulate-rich and solid particulate-lean substages of the treatment fluid stage into the fracture, wherein at least a portion of the particulate-rich substage comprises a self-agglomerating solid composition and a foamed carrying fluid, wherein a volume of each of the solid particulate-rich substages is larger than a respective volume of an adjacent one [immediately preceding or following] of the solid particulate-lean substages to form a plurality of solid particulate-rich island regions in the fracture and an interconnected network of open channel regions between the island regions;   channelizing the particulate-rich island regions in situ in the fracture to form particulate clusters within the island regions separated from adjacent particulate clusters by open voids in the island regions;   reducing pressure in the fracture to close the fracture onto the island regions; and   hydraulically conducting fluid flow through the open channel regions between the formation and the wellbore.   
     
     
         16 . The method of  claim 15 , wherein the solid particulate-rich substages each comprise alternating pulses injected at different rates. 
     
     
         17 . The method of  claim 15 , wherein the solid particulate-rich substages each comprise alternating pulses comprising a substantially uniform distribution of one or more components in the alternate pulses and a heterogeneous distribution between alternate pulses of at least one other component. 
     
     
         18 . The method of  claim 15 , wherein the particulate-rich substages each comprise alternating pulses comprising a substantially uniform distribution of one or more components in the alternate pulses, and a heterogeneous distribution between alternate pulses of another component selected from the solid particulate, foam quality (gas), fibers, anchorant, agglomerant, agglomerant aid, agglomerant aid activator, binding liquid, an induced settling trigger, viscous gel macrostructures, and combinations thereof. 
     
     
         19 . The method of  claim 15 , wherein the particulate-rich substages each comprise alternating pulses comprising a substantially uniform distribution of one or more components with respect to a liquid phase of the carrying fluid in the alternate pulses, and a heterogeneous distribution between alternate pulses of foam quality (volume percent gas), wherein the foam quality is alternated between values different by at least 5 percent. 
     
     
         20 . The method of  claim 15 , wherein the carrying fluid comprises a viscoelastic surfactant. 
     
     
         21 . The method of  claim 15 , wherein the treatment fluid stage comprises a pH control agent. 
     
     
         22 . The method of  claim 15 , wherein the treatment fluid stage comprises an ester and further comprising releasing an acid from the ester. 
     
     
         23 . The method of  claim 15 , wherein the solid particulate-lean substages comprise fiber. 
     
     
         24 . The method of  claim 15 , wherein the solid particulate-rich substages comprise a slurry of the solid particulate freely dispersed in fluid spaces around macrostructures [gel blobs or fibers] suspended in a carrying fluid. 
     
     
         25 . The method of  claim 15 , wherein the solid particulate-rich substages and the solid particulate-lean substages in the treatment stage fluid have an overall volumetric ratio from 60:40 to 95:5. 
     
     
         26 . The method of  claim 15 , wherein the solid particulate-rich substages provide at least a minimum coverage of propped regions comprising the islands and a channel breadth between the propped regions sufficiently small to inhibit collapse of the open channel regions in the interconnected network. 
     
     
         27 . A system to treat a fracture interval of a formation penetrated by a wellbore, comprising:
 a subterranean formation penetrated by a wellbore;   a treatment fluid stage disposed at least partially in the wellbore, the treatment fluid stage comprising solid particulate-rich and solid particulate-lean substages, wherein a volume of each of the solid particulate-rich substages is larger than a respective volume of an adjacent one of the solid particulate-lean substages to form a plurality of solid particulate-rich island regions in the fracture and an interconnected network of open channel regions between the island regions;   the solid particulate-rich substages each comprising alternating pulses comprising a substantially uniform distribution of one or more components with respect to a liquid phase of a carrying fluid in the alternate pulses, and a heterogeneous foam quality to channelize the particulate-rich island regions in situ in the fracture to form particulate clusters within the island regions separated from adjacent particulate clusters by open voids within the island regions;   a pump system to pump 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   a shut in system to close the fracture onto the solid particulate-rich island regions.