Well treatment methods and systems

Abstract

Methods, fluids, equipment and/or systems for treating a subterranean formation penetrated by a wellbore, which use less water, less energy, less equipment, have a smaller wellsite footprint, a reduced carbon dioxide emission, an improved distribution of proppant among a plurality of flow paths, an improved stimulation of reservoir fluid production, an improved risk management method, or the like, or any combination thereof, relative to comparable conventional treatment methods, fluids, equipment and/or systems such as, for example, hydraulic fracture treatments of subterranean formations using slickwater and/or high-viscosity treatment fluids.

We claim: 
     
         1 . A method, comprising:
 injecting a proppant-containing treatment fluid into a low mobility subterranean formation;   creating a fracture in the subterranean formation containing a first volume (V 1 ) of the proppant-containing treatment fluid; and   allowing the fracture to close on the proppant to form a proppant-supported fracture having a second volume (V 2 ) of packed proppant support, wherein a ratio of the second volume (V 2 ) to the first volume (V 1 ) is at least 0.7.   
     
     
         2 . The method of  claim 1 , wherein the low mobility formation comprises a carbonate or siltstone formation. 
     
     
         3 . The method of  claim 1 , wherein the low mobility formation comprises permeability less than 0.1 mD and further comprising producing hydrocarbon liquid from the formation. 
     
     
         4 . The method of  claim 1 , wherein the low mobility formation comprises permeability less than 1000 nD and further comprising producing hydrocarbon gas from the formation. 
     
     
         5 . The method of  claim 1 , comprising forming the proppant-supported fracture to extend away from a wellbore for a distance of at least 30 m (98 feet) into the subterranean formation. 
     
     
         6 . The method of  claim 1 , further comprising placing the packed proppant support in pillars and forming open channels in spaces between the pillars. 
     
     
         7 . The method of  claim 1 , wherein the proppant-containing treatment fluid comprises a viscosity less than 300 mPa-s (170 s −1 , 25° C.) and a yield stress between 1 and 20 Pa (2.1-42 lb f /ft 2 ). 
     
     
         8 . The method of  claim 1 , wherein the proppant-containing treatment fluid comprises 0.36 L or more of proppant volume per liter of proppant-containing treatment fluid (8 ppa proppant), a viscosity less than 300 mPa-s (170 s −1 , 25° C.), a solids phase having a packed volume fraction (PVF) greater than 0.72, a slurry solids volume fraction (SVF) less than the PVF and a ratio of SVF/PVF greater than about 1−2.1*(PVF−0.72). 
     
     
         9 . The method of  claim 1 , further comprising:
 injecting the proppant-containing treatment fluid via a wellbore at a sustained perforation velocity of less than 50 m/s for a continuous period of at least 5 minutes to create a fracture in the subterranean formation; and   placing the proppant into the fracture and closing the fracture to form a proppant-supported fracture for a distance of at least 30 meters (98 feet) away from the wellbore.   
     
     
         10 . The method of  claim 1 , further comprising:
 stopping injection of the treatment fluid to interrupt the creation of the fracture thereby stranding the treatment fluid in the wellbore; and   thereafter resuming injection of the treatment fluid to inject the stranded treatment fluid into the formation and continue the fracture creation.   
     
     
         11 . A method to improve proppant pumping energy efficiency in a fracturing procedure comprising pumping a proppant-containing treatment fluid at a surface treatment pressure into a wellbore in fluid communication with a subterranean formation, injecting the proppant-containing treatment fluid from the wellbore into a subterranean formation to create a fracture, placing the proppant into the fracture and closing the fracture to form a proppant-supported fracture extending away from the wellbore and in fluid communication therewith, the improvement comprising:
 preparing the proppant-containing treatment fluid to comprise at least 0.36 L of proppant per liter of whole fluid and a viscosity less than 300 mPa-s (170 s −1 , 25° C.);   stabilizing the proppant-containing treatment fluid to form a stabilized treatment slurry (STS) meeting at least one of the following conditions:
 a) the slurry has a low-shear viscosity equal to or greater than 1 Pa-s (5.11 s-1, 25° C.); 
 b) the slurry has a Herschel-Buckley (including Bingham plastic) yield stress (as determined in the manner described herein) equal to or greater than 1 Pa; or 
 c) the largest particle mode in the slurry has a static settling rate less than 0.01 mm/hr; or 
 d) the depth of any free fluid at the end of a 72-hour static settling test condition or an 8 h@15 Hz/10 d-static dynamic settling test condition (4 hours vibration followed by 20 hours static followed by 4 hours vibration followed finally by 10 days of static conditions) is no more than 2% of total depth; or 
 e) the apparent dynamic viscosity (25° C., 170 s-1) across column strata after the 72-hour static settling test condition or the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than +/−20% of the initial dynamic viscosity; or 
 f) the slurry solids volume fraction (SVF) across the column strata below any free water layer after the 72-hour static settling test condition or the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than 5% greater than the initial SVF; or 
 g) the density across the column strata below any free water layer after the 72-hour static settling test condition or the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than 1% of the initial density. 
   pumping the STS to the surface treatment pressure for introduction into the wellbore.   
     
     
         12 . The method of  claim 11 , wherein the proppant-supported fracture extends for a distance of at least 30 meters (98 feet) away from the wellbore. 
     
     
         13 . The method of  claim 11 , wherein the STS is pumped to surface treatment pressure with a proppant pumping energy efficiency of at least 2 L of proppant pumped per MJ of pumping energy. 
     
     
         14 . The method of  claim 11 , wherein:
 1. the depth of any free fluid at the end of the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than 2% of total depth;   2. the apparent dynamic viscosity (25° C., 170 s −1 ) across column strata after the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than +/−20% of the initial dynamic viscosity;   3. The slurry solids volume fraction (SVF) across the column strata below any free water layer after the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than 5% greater than the initial SVF; and   4. The density across the column strata below any free water layer after the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than 1% of the initial density.   
     
     
         15 . The method of  claim 11 , wherein the STS is formed by at least one of: (1) introducing sufficient particles into the slurry or treatment fluid to increase the SVF of the treatment fluid to at least 0.4; (2) increasing a low-shear viscosity of the slurry or treatment fluid to at least 1 Pa-s (5.11 s-1, 25° C.); (3) increasing a yield stress of the slurry or treatment fluid to at least 1 Pa; (4) increasing apparent viscosity of the slurry or treatment fluid to at least 50 mPa-s (170 s-1, 25° C.); (5) introducing a multimodal solids phase into the slurry or treatment fluid; (6) introducing a solids phase having a PVF greater than 0.7 into the slurry or treatment fluid; (7) introducing into the slurry or treatment fluid a viscosifier selected from viscoelastic surfactants, e.g., in an amount ranging from 0.01 up to 7.2 g/L (60 ppt), and hydratable gelling agents, e.g., in an amount ranging from 0.01 up to 4.8 g/L (40 ppt) based on the volume of fluid phase; (8) introducing colloidal particles into the slurry or treatment fluid; (9) reducing a particle-fluid density delta to less than 1.6 g/mL (e.g., introducing particles having a specific gravity less than 2.65 g/mL, carrier fluid having a density greater than 1.05 g/mL or a combination thereof); (10) introducing particles into the slurry or treatment fluid having an aspect ratio of at least 6; (11) introducing ciliated or coated proppant into slurry or treatment fluid; and (12) combinations thereof. 
     
     
         16 . The method of  claim 11 , further comprising maintaining a relatively low perforation pressure drop corresponding to a sustained velocity of the treatment fluid through the perforations below 50 m/s, relative to the pressure drop of the treating fluid passing through the perforation at a higher velocity. 
     
     
         17 . The method of  claim 11 , further comprising lowering friction pressure drop in the wellbore by maintaining a sustained flow rate of treatment fluid in the wellbore below 1.6 m 3 /min (10 BPM). 
     
     
         18 . A method, comprising:
 preparing a treatment plan for fracturing a subterranean formation penetrated by a wellbore, wherein the treatment plan comprises a schedule for pumping into the wellbore one or more treatment fluids specified in the treatment plan including a stabilized proppant-containing treatment fluid comprising at least 0.36 L of proppant per liter of whole fluid, a packed volume fraction (PVF) greater than a slurry solids volume fraction (SVF), and a viscosity less than 300 mPa-s (170 s −1 , 25° C.), and wherein a spurt loss (Vspurt) is less than 10 vol % of a fluid phase of the stabilized proppant-containing treatment fluid or less than 50 vol % of an excess fluid phase (Vspurt<0.50*(PVF−SVF));   injecting the stabilized proppant-containing treatment fluid into the subterranean formation according to the treatment plan to create a fracture, wherein the spurt loss is sufficiently low to maintain fluidity of the stabilized proppant-containing treatment fluid entering the fracture; and   placing the proppant into the fracture and closing the fracture to form a proppant-supported fracture for a distance of at least 30 meters (98 feet) away from the wellbore.   
     
     
         19 . The method of  claim 18 , wherein the sum of spurt volume (Vspurt) plus continuous fluid loss into the formation matrix (Vw) during the treatment fluid injection is greater than the total volume of fluid phase (Vfluid), according to the equation [(Vw+Vspurt)>(Vtreatmentfluid*(1−SVF))], wherein Vw=4*A*Cw*t 1   −0.5  wherein Vtreatmentfluid is the volume of treatment fluid injected into the fracture, A is the exposed area of one fracture face, Cw is the loss coefficient, and t 1  is the duration of the treatment fluid injection. 
     
     
         20 . The method of  claim 19 , further comprising immediately producing hydrocarbons from the formation via the fracture wherein a fluid phase flowback recovery volume (Vflowback) at a flowback recovery ratio (Vflowback/Vw where Vw is the fluid phase volume of the treatment fluid) is less than 1% over an initial production period of 5 days (FRR5).